UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 1995
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from to
Commission File Number 1-3473
TESORO PETROLEUM CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
Delaware 95-0862768
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
8700 Tesoro Drive
San Antonio, Texas 78217
(Address of Principal Executive Offices)
(Zip Code)
210-828-8484
(Registrant's Telephone Number, Including Area Code)
=============
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
------ ------
=============
There were 24,535,458 shares of the Registrant's Common Stock outstanding at
July 31,1995.
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1995
PART I. FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - June 30, 1995
and December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations - Three
Months and Six Months Ended June 30, 1995 and 1994 . . . . . . . . 4
Condensed Statements of Consolidated Cash Flows - Six Months
Ended June 30, 1995 and 1994 . . . . . . . . . . . . . . . . . . . 5
Notes to Condensed Consolidated Financial Statements . . . . . . . 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . . . . . . . 10
PART II. OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . 22
Item 4. Submission of Matters to a Vote of Security Holders . . . . 24
Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . 24
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Dollars in thousands except per share amounts)
June 30, December 31,
1995 1994*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents. . . . . . . . . . . . $ 7,356 14,018
Receivables, less allowance for doubtful accounts
of $1,962 ($1,816 at December 31, 1994) . . . . 64,489 73,406
Receivable from Tennessee Gas Pipeline Company
(Note 4) . . . . . . . . . . . . . . . . . . . 35,381 17,734
Inventories:
Crude oil and wholesale refined products,
at LIFO . . . . . . . . . . . . . . . . . . . 53,926 58,798
Merchandise and retail refined products . . . . 4,564 5,934
Materials and supplies. . . . . . . . . . . . . 3,867 3,570
Prepaid expenses and other . . . . . . . . . . . 13,661 8,648
--------- ---------
Total Current Assets. . . . . . . . . . . . . . 183,244 182,108
PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated
Depreciation, Depletion and Amortization of
$228,708 ($205,782 at December 31, 1994) . . . . 285,623 273,334
INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . 13,248 10,295
OTHER ASSETS . . . . . . . . . . . . . . . . . . . 20,487 18,623
--------- ---------
TOTAL ASSETS . . . . . . . . . . . . . . . $ 502,602 484,360
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable . . . . . . . . . . . . . . . . $ 58,307 53,573
Accrued liabilities. . . . . . . . . . . . . . . 33,292 35,266
Current portion of long-term debt and other
obligations . . . . . . . . . . . . . . . . . . 8,694 7,404
--------- ---------
Total Current Liabilities . . . . . . . . . . . 100,293 96,243
--------- ---------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . 4,744 4,582
--------- ---------
OTHER LIABILITIES. . . . . . . . . . . . . . . . . 37,352 30,593
--------- ---------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT PORTION. . . . . . . . . . . . . . . . . 189,096 192,210
--------- ---------
COMMITMENTS AND CONTINGENCIES (Notes 3 and 4)
STOCKHOLDERS' EQUITY:
Common Stock, par value $.16-2/3; authorized
50,000,000 shares; 24,539,497 shares issued
and outstanding (24,389,801 in 1994) . . . . . 4,090 4,065
Additional paid-in capital . . . . . . . . . . . 176,658 175,514
Accumulated deficit. . . . . . . . . . . . . . . ( 9,631) ( 18,847)
--------- ---------
Total Stockholders' Equity. . . . . . . . . . . 171,117 160,732
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 502,602 484,360
========= =========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
* The balance sheet at December 31, 1994 has been taken from the audited
consolidated financial statements at that date and condensed.
3
<TABLE>
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Unaudited)
(In thousands except per share amounts)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
1995 1994 1995 1994
---- ---- ---- ----
<S> <C> <C> <C> <C>
REVENUES:
Gross operating revenues . . . . . . . . . . . . . $ 265,129 210,660 499,830 399,747
Interest income. . . . . . . . . . . . . . . . . . 188 452 424 975
Gain (loss) on sales of assets . . . . . . . . . . ( 9) ( 339) ( 2) 2,341
Other. . . . . . . . . . . . . . . . . . . . . . . 130 272 211 722
--------- --------- --------- ---------
Total Revenues. . . . . . . . . . . . . . . . . . 265,438 211,045 500,463 403,785
--------- --------- --------- ---------
COSTS AND EXPENSES:
Costs of sales and operating expenses . . . . . . 234,501 191,228 445,112 358,833
General and administrative . . . . . . . . . . . . 4,185 3,377 7,999 7,004
Depreciation, depletion and amortization . . . . . 11,412 7,718 23,327 14,395
Interest expense, net of $240 capitalized in 1994. 5,368 4,629 10,661 9,506
Other. . . . . . . . . . . . . . . . . . . . . . . 1,093 2,252 2,015 3,443
--------- --------- --------- ---------
Total Costs and Expenses. . . . . . . . . . . . . 256,559 209,204 489,114 393,181
--------- --------- --------- ---------
EARNINGS BEFORE INCOME TAXES AND
EXTRAORDINARY LOSS ON
EXTINGUISHMENT OF DEBT . . . . . . . . . . . . . . 8,879 1,841 11,349 10,604
Income Tax Provision . . . . . . . . . . . . . . . . 1,423 611 2,133 2,172
--------- --------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY LOSS
ON EXTINGUISHMENT OF DEBT. . . . . . . . . . . . . 7,456 1,230 9,216 8,432
Extraordinary Loss on Extinguishment of Debt . . . . - - - ( 4,752)
--------- --------- --------- ---------
NET EARNINGS . . . . . . . . . . . . . . . . . . . . 7,456 1,230 9,216 3,680
Dividend Requirements on Preferred Stocks . . . . . - 791 - 2,680
--------- --------- --------- ---------
NET EARNINGS APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . . . . . . . $ 7,456 439 9,216 1,000
========= ========= ========= =========
EARNINGS (LOSS) PER PRIMARY AND
FULLY DILUTED<F1> SHARE:
Earnings Before Extraordinary Loss on
Extinguishment of Debt. . . . . . . . . . . . . . $ .30 .02 .37 .27
Extraordinary Loss on Extinguishment of Debt . . . - - - ( .22)
--------- --------- --------- ---------
Net Earnings . . . . . . . . . . . . . . . . . . . $ .30 .02 .37 .05
========= ========= ========= =========
AVERAGE OUTSTANDING COMMON AND
COMMON EQUIVALENT SHARES . . . . . . . . . . . . . 25,206 23,222 25,163 21,350
========= ========= ========= =========
<FN>
<F1> Anti-dilutive.
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
4
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
(In thousands)
Six Months Ended
June 30,
--------------------
1995 1994
---- ----
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings . . . . . . . . . . . . . . . . . . . . . $ 9,216 3,680
Adjustments to reconcile net earnings to net cash
from operating activities:
Depreciation, depletion and amortization . . . . . . 23,327 14,395
Loss on extinguishment of debt. . . . . . . . . . . . - 4,752
Loss (gain) on sales of assets . . . . . . . . . . . 2 ( 2,341)
Amortization of deferred charges and other, net . . . 786 792
Changes in assets and liabilities:
Receivables . . . . . . . . . . . . . . . . . . . . 8,917 2,767
Receivable from Tennessee Gas Pipeline Company . . . (17,647) ( 9,751)
Inventories . . . . . . . . . . . . . . . . . . . . 6,146 12,483
Investment in Tesoro Bolivia Petroleum Company . . . ( 2,953) ( 2,127)
Other assets . . . . . . . . . . . . . . . . . . . . ( 4,351) ( 1,824)
Accounts payable and other current liabilities . . . 5,855 22,103
Obligation payments to State of Alaska . . . . . . . ( 1,316) ( 1,320)
Other liabilities and obligations . . . . . . . . . 1,461 1,442
--------- ---------
Net cash from operating activities . . . . . . . . 29,443 45,051
--------- ---------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . (32,758) (44,911)
Acquisition of Kenai Pipe Line Company . . . . . . . . ( 3,000) -
Proceeds from sales of assets. . . . . . . . . . . . . 1,015 2,247
Sales of short-term investments . . . . . . . . . . . - 5,952
Purchases of short-term investments. . . . . . . . . . - ( 1,974)
Other. . . . . . . . . . . . . . . . . . . . . . . . . ( 172) 3,850
--------- ---------
Net cash used in investing activities . . . . . . (34,915) (34,836)
--------- ---------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments, net of borrowings of $159,500 in 1995
and $5,000 in 1994, under revolving credit facilities - ( 5,000)
Payments of long-term debt . . . . . . . . . . . . . . ( 1,200) ( 855)
Proceeds from issuance of common stock, net. . . . . . - 56,967
Repurchase of common and preferred stock . . . . . . . - (52,948)
Dividends on preferred stocks. . . . . . . . . . . . . - ( 1,684)
Costs of recapitalization and other. . . . . . . . . . 10 ( 1,985)
--------- ---------
Net cash used in financing activities. . . . . . . ( 1,190) ( 5,505)
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . ( 6,662) 4,710
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . 14,018 36,596
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . $ 7,356 41,306
========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid, net of $240 capitalized in 1994 . . . . $ 9,013 9,229
========= =========
Income taxes paid . . . . . . . . . . . . . . . . . . $ 2,389 2,756
========= =========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
5
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Basis of Presentation
The interim condensed consolidated financial statements are unaudited but, in
the opinion of management, incorporate all adjustments necessary for a fair
presentation of results for such periods. Such adjustments are of a normal
recurring nature. The preparation of these condensed consolidated financial
statements required the use of management's best estimates and judgment. The
results of operations for any interim period are not necessarily indicative of
results for the full year. The accompanying condensed consolidated financial
statements should be read in conjunction with the consolidated financial
statements and notes thereto contained in the Company's Annual Report on Form
10-K for the year ended December 31, 1994.
(2) Acquisition
In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe
Line Company ("KPL") for $3 million. The Company transports its crude oil and a
substantial portion of its refined products utilizing KPL's pipeline and marine
terminal facilities in Kenai, Alaska.
(3) Revolving Credit Facility
Under the terms of its Revolving Credit Facility, as amended, the Company is
required to maintain specified levels of working capital, tangible net worth,
consolidated cash flow and refinery cash flow, as defined. Among other matters,
the Revolving Credit Facility contains certain restrictions with respect to (i)
capital expenditures, (ii) incurrence of additional indebtedness, and (iii)
dividends on capital stock. The Revolving Credit Facility contains other
covenants customary in credit arrangements of this kind. At June 30, 1995, the
Company did not satisfy the refinery cash flow requirement, which required the
Company to obtain a waiver to the Revolving Credit Facility. Compliance with
certain financial covenants under the Revolving Credit Facility is primarily
dependent on the Company's maintenance of specified levels of cash flows from
operations, capital expenditures, levels of borrowings and the value of the
Company's domestic oil and gas reserves. Based on current depressed refinery
margins, the Company will be required to seek a waiver or an amendment to the
Revolving Credit Facility from its banks with respect to its refinery cash flow
requirement for the remainder of 1995. The Company believes it will be able to
negotiate terms and conditions with its banks under the Revolving Credit
Facility which will allow the Company to adequately finance its operations.
(4) Commitments and Contingencies
Gas Purchase and Sales Contract
The Company is selling a portion of the gas from its Bob West Field to Tennessee
Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement
("Tennessee Gas Contract") which provides that the price of gas shall be the
maximum price as calculated in accordance with Section 102(b)(2) ("Contract
Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990,
Tennessee Gas filed suit against the Company in the District Court of Bexar
County, Texas, alleging that the Tennessee Gas Contract is not applicable to the
Company's properties and that the gas sales price should be the price calculated
under the provisions of Section 101 of the NGPA rather than the Contract Price.
During June 1995, the Contract Price was in excess of $8.00 per Mcf, the Section
101 price was $4.94 per Mcf and the average spot market price was $1.56 per Mcf.
Tennessee Gas also claimed that the contract should be considered an "output
contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and
that the increases in volumes tendered under the contract exceeded those
allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the
6
remaining Tennessee Gas claims in the Supreme Court of Texas. The appellate
court decision was the first decision reported in Texas holding that a
take-or-pay contract was an output contract. The Supreme Court of Texas heard
arguments in December 1994, regarding the output contract issue and certain of
the issues raised by Tennessee Gas. On August 1, 1995, the Supreme Court of
Texas, in a divided opinion, affirmed the decision of the appellate court on all
issues, determined that the Tennessee Gas Contract was an output contract and
remanded the case to the trial court for determination of whether gas volumes
tendered by the Company to Tennessee Gas were tendered in good faith and were
not unreasonably disproportionate to any normal or otherwise comparable prior
output or stated estimates in accordance with Section 2.306 of the UCC. In
addition, the Supreme Court affirmed that the price under the Tennessee Gas
Contract is the Contract Price. The Company intends to file a motion for
rehearing before the Texas Supreme Court on the issue of whether the Tennessee
Gas Contract is an output contract. Through June 30, 1995, under the Tennessee
Gas Contract, the Company recognized cumulative revenues in excess of spot
market prices through September 17, 1994, and in excess of a nonrefundable $3.00
per Mcf bond price subsequent to September 17, 1994, totaling $86.6 million of
which $33.9 million is included in receivables. The Company and its outside
counsel are evaluating the impact of various aspects of the Supreme Court
decision. The Company believes that, if this issue is tried, the gas volumes
tendered to Tennessee Gas will be found to have been in good faith and otherwise
in accordance with the requirements of the UCC. However, there can be no
assurance as to the ultimate outcome at trial. An adverse outcome of this
litigation could require the Company to reverse some or all of the incremental
revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts
received above spot market prices, plus interest if awarded by the court.
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995, a
hearing was held before the trial court regarding the extension of the Tennessee
Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the
period August 14, 1995, until the earlier of October 16, 1995, or the date the
Supreme Court issues its rulings on motions for rehearing, (i) continue to take
at least its entire take-or-pay volume obligation, (ii) pay for gas at a price
of $3.00 per Mmbtu subject to potential refund of amounts in excess of market
prices if Tennessee Gas should ultimately prevail in the litigation, and (iii)
post a $25 million bond in addition to the $120 million bond presently in place.
Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond
Price until August 14, 1995.
Environmental
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which change frequently, regulate the discharge of
materials into the environment and may require the Company to remove or mitigate
the environmental effects of the disposal or release of petroleum or chemical
substances at various sites or install additional controls or other
modifications or changes in use for certain emission sources. The Company is
currently involved with a waste disposal site in Louisiana at which it has been
named a potentially responsible party under the Federal Superfund law. Although
this law might impose joint and several liability upon each party at the site,
the extent of the Company's allocated financial contributions to the cleanup of
this site is expected to be limited based upon the number of companies and the
volumes of waste involved. The Company believes that its liability at this site
is expected to be limited based upon the payment by the Company of a de minimis
settlement amount of $2,500 at a similar site in Louisiana. The Company is also
involved in remedial responses and has incurred cleanup expenditures associated
with environmental matters at a number of sites, including certain of its own
properties. In addition, the Company is holding discussions with the Department
of Justice ("DOJ") concerning the assessment of penalties with respect to
certain alleged violations of regulations promulgated under the Clean Air Act as
discussed below.
In March 1992, the Company received a Compliance Order and Notice of Violation
from the Environmental Protection Agency ("EPA") alleging violations by the
Company of the New Source Performance Standards under the Clean Air Act at its
Alaska refinery. These allegations include failure to install, maintain and
operate
7
monitoring equipment over a period of approximately six years, failure to
perform accuracy testing on monitoring equipment, and failure to install certain
pollution control equipment. From March 1992 to July 1993, the EPA and the
Company exchanged information relevant to these allegations. In addition, the
EPA conducted an environmental audit of the Company's refinery in May 1992. As
a result of this audit, the EPA is also alleging violation of certain
regulations related to asbestos materials. In October 1993, the EPA referred
these matters to the DOJ. The DOJ contacted the Company to begin negotiating a
resolution of these matters. The DOJ has indicated that it is willing to enter
into a judicial consent decree with the Company and that this decree would
include a penalty assessment. Negotiations on the penalty are in progress. The
DOJ has currently proposed a penalty assessment of approximately $2.3 million.
The Company is continuing to negotiate with the DOJ but cannot predict the
ultimate outcome of the negotiations.
At June 30, 1995, the Company's accruals for environmental matters, including
the alleged violations of the Clean Air Act, amounted to $11.3 million. Also
included in this amount is an approximate $4 million noncurrent liability for
remediation of the KPL properties, which liability has been funded by the former
owners of KPL through a restricted escrow deposit. Based on currently available
information, including the participation of other parties or former owners in
remediation actions, the Company believes these accruals are adequate. In
addition, to comply with environmental laws and regulations, the Company
anticipates that it will be required to make capital improvements in 1995 of
approximately $2 million, primarily for the removal and upgrading of underground
storage tanks, and approximately $8 million during 1996 for the installation of
dike liners required under Alaska environmental regulations. Conditions that
require additional expenditures may exist for various Company sites, including,
but not limited to, the Company's refinery, retail gasoline outlets (current and
closed locations) and petroleum product terminals, and for compliance with the
Clean Air Act. The amount of such future expenditures cannot currently be
determined by the Company.
Crude Oil Purchase Contract
The Company's contract with the State of Alaska ("State") for the purchase of
royalty crude oil expires on December 31, 1995. In May 1995, the Company
renegotiated a new three-year contract with the State for the period January 1,
1996 through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of Alaska North Slope ("ANS") royalty crude
oil, the primary feedstock for the Company's refinery, and is priced at the
weighted average price reported to the State by a major North Slope producer for
ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline
System. Under this agreement, the Company is required to utilize in its
refinery operations volumes equal to at least 80% of the ANS crude oil to be
purchased from the State. This contract contains provisions that allow the
Company to temporarily or permanently reduce its purchase obligations.
Other
In February 1995, a lawsuit was filed in the U.S. District Court for the
Southern District of Texas, McAllen Division, by the Heirs of H.P. Guerra,
Deceased ("Plaintiffs") against the United States and Tesoro and other working
and overriding royalty interest owners to recover the oil and gas mineral estate
under 2,706.34 acres situated in Starr County, Texas. The oil and gas mineral
estate sought to be recovered underlies lands taken by the United States in
connection with the construction of the Falcon Dam and Reservoir. In their
lawsuit, the Plaintiffs allege that the original taking by the United States in
1948 was unlawful and void and the refusal of the United States to revest the
mineral estate to H.P. Guerra or his heirs was arbitrary and capricious and
unconstitutional. Plaintiffs seek (i) restoration of their oil and gas estate;
(ii) restitution of all proceeds realized from the sale of oil and gas from
their mineral estate, plus interest on the value thereof; and (iii) cancellation
of all oil and gas leases issued by the United States to Tesoro and the other
working interest owners covering their mineral estate. The lawsuit covers a
significant portion of the mineral estate in the Bob West Field; however, none
of the acreage covered is dedicated to the Tennessee Gas Contract. The Company
cannot predict the ultimate resolution of this matter but, based upon advice
from outside legal counsel, believes the lawsuit is without merit.
In July 1994, a former customer of the Company ("Customer"), filed suit against
the Company in the United States District Court for the District of New Mexico
for a refund in the amount of approximately $1.2 million, plus
8
interest of approximately $4.4 million and attorney's fees, related to a
gasoline purchase from the Company in 1979. The Customer also alleges
entitlement to treble damages and punitive damages in the aggregate amount of
$16.8 million. The refund claim is based on allegations that the Company
renegotiated the acquisition price of gasoline sold to the Customer and failed
to pass on the benefit of the renegotiated price to the Customer in violation of
Department of Energy price and allocation controls then in effect. In May 1995,
the court issued an order granting the Company's motion for summary judgment and
dismissed with prejudice all the claims in the Customer's complaint. In June
1995, the Customer filed a notice of appeal with the U.S. Court of Appeals for
the Federal Circuit. The Company cannot predict the ultimate resolution of this
matter but believes the claim is without merit.
(5) Oil and Gas Producing Activities
The Company has entered into a price swap with another company for approximately
8.25 Bcf of its anticipated U.S. natural gas production for the period April 1,
1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf.
For the three months and six months ended June 30, 1995, the Company's average
spot market sales prices, which included the effect of this price swap, were
$1.52 and $1.48 per Mcf, respectively.
The Company's mid-year reserve report, prepared by the Company's independent
petroleum consultants, estimates that, during the first half of 1995, Tesoro's
proved domestic natural gas reserves increased 53%, from 129 Bcf of natural gas
at December 31, 1994, to 198 Bcf at June 30, 1995, after net production during
this period of approximately 23 Bcf. As a result, this change in estimate
reduced depreciation, depletion and amortization expense and increased net
earnings for the three months ended June 30, 1995 by approximately $4 million
($.16 per share).
The Company continues to assess its existing asset base in order to maximize
returns and financial flexibility through diversification, acquisitions and
divestitures in all of its operating segments. This ongoing assessment
includes, in the Exploration and Production segment, evaluating ways in which
the Company might diversify the mix of its oil and gas assets, reduce the asset
concentration associated with the Bob West Field and lower future capital
commitments. In these regards, the Company is evaluating offers to sell or
exchange approximately 40% of its total proved domestic natural gas reserves in
the Bob West Field. The proved reserves for which offers are being evaluated
are located in the C, D, E and F units of the Bob West Field and do not include
acreage covered by the Tennessee Gas Contract (see Note 4). No offer for a sale
or exchange has been accepted and there is no assurance that a sale or exchange
will be consummated. The Company is uncertain as to the impact of these
initiatives upon its capital resources and liquidity, if any.
9
Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS - THREE AND SIX MONTHS ENDED JUNE 30, 1995 COMPARED WITH
THREE AND SIX MONTHS ENDED JUNE 30, 1994
A consolidated summary of the Company's operations for the three and six months
ended June 30, 1995 and 1994 is presented below (in millions except per share
amounts):
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
<S> <C> <C> <C> <C>
Summary of Operations
Segment Operating Profit (Loss)<F1>:
Refining and Marketing . . . . . . . . . . . . . . . $ ( 2.7) ( 5.0) ( 7.3) 1.4
Exploration and Production - United States . . . . . 20.0 14.6 36.6 25.8
Exploration and Production - Bolivia . . . . . . . . 2.3 2.5 4.0 4.4
Oil Field Supply and Distribution. . . . . . . . . . ( .5) ( .4) ( 1.8) ( 1.6)
-------- ------- ------- --------
Total Segment Operating Profit. . . . . . . . . . . 19.1 11.7 31.5 30.0
Corporate and Unallocated Costs:
Interest expense . . . . . . . . . . . . . . . . . . 5.4 4.6 10.7 9.5
Interest income. . . . . . . . . . . . . . . . . . . ( .2) ( .5) ( .4) ( 1.0)
General and administrative expenses. . . . . . . . . 4.2 3.4 8.0 7.0
Other. . . . . . . . . . . . . . . . . . . . . . . . .9 2.3 1.9 3.8
-------- ------- ------- --------
Earnings Before Income Taxes and Extraordinary Loss . 8.8 1.9 11.3 10.7
Income Tax Provision . . . . . . . . . . . . . . . . . 1.4 .6 2.1 2.2
-------- ------- ------- --------
Earnings Before Extraordinary Loss . . . . . . . . . . 7.4 1.3 9.2 8.5
Extraordinary Loss on Extinguishment of Debt . . . . . - - - ( 4.8)
-------- ------- ------- --------
Net Earnings . . . . . . . . . . . . . . . . . . . . . 7.4 1.3 9.2 3.7
Dividend Requirements on Preferred Stocks. . . . . . . - .8 - 2.7
-------- ------- ------- --------
Net Earnings Applicable to Common Stock. . . . . . . . $ 7.4 .5 9.2 1.0
======== ======= ======= ========
Earnings (Loss) per Primary and Fully Diluted<F2> Share:
Earnings Before Extraordinary Loss . . . . . . . . . $ .30 .02 .37 .27
Extraordinary Loss on Extinguishment of Debt . . . . - - - ( .22)
-------- ------- ------- --------
Net Earnings . . . . . . . . . . . . . . . . . . . . $ .30 .02 .37 .05
======== ======= ======= ========
<FN>
<F1> Operating profit (loss) represents pretax earnings (loss) before certain
corporate expenses, interest income and interest expense.
<F2> Anti-dilutive.
</TABLE>
Net earnings applicable to common stock of $7.4 million, or $.30 per share, for
the three months ended June 30, 1995 ("1995 quarter") compare with net earnings
applicable to common stock of $.5 million, or $.02 per share, for the three
months ended June 30, 1994 ("1994 quarter"). Net earnings for the 1995 quarter
included an aggregate benefit of approximately $4 million, or $.16 per share,
due to additions to the Company's proved domestic natural gas reserves which
reduced the domestic depletion rate to $.62 per Mcf, as compared to $.90 per Mcf
for the 1995 first quarter. Net earnings for the 1994 quarter were reduced by
$.8 million of dividend requirements on preferred stock. When comparing the
1995 quarter to the 1994 quarter, the increase in net earnings was primarily due
to the successful drilling program and increased natural gas production from the
Company's exploration and production operations in South Texas partially offset
by lower spot market prices for sales of natural gas. In addition, during the
1995 quarter, the Company narrowed its operating loss from the refining and
marketing segment to $2.7 million.
Net earnings applicable to common stock of $9.2 million, or $.37 per share, for
the six months ended June 30, 1995 ("1995 period") compare to net earnings
applicable to common stock of $1.0 million, or $.05 per share, for the six
months ended June 30, 1994 ("1994 period"). The comparability between these two
periods was impacted by certain significant transactions. As discussed above,
the 1995 period included an aggregate benefit of approximately $4 million
resulting from a reduced depletion rate. Net earnings for the 1994 period were
reduced by $2.7 million of dividend requirements on preferred stock. Also
included in the 1994 period was a noncash extraordinary loss of $4.8 million, or
$.22 per share, attributable to the early extinguishment of debt in connection
with a recapitalization in 1994. Earnings before the extraordinary loss were
$8.5 million, or $.27 per share, for the 1994 period. The 1994 period was
favorably impacted by a gain of $2.4 million, or $.11 per share, from the sale
of assets. Excluding these significant transactions for both periods, the
decrease in net earnings was
10
largely due to lower operating results from the Company's refining and marketing
segment and lower spot market prices for sales of natural gas, partially offset
by increased natural gas production from the Company's exploration and
production operations in South Texas.
11
<TABLE>
<CAPTION>
Refining and Marketing Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions except per barrel amounts)
<S> <C> <C> <C> <C>
Gross Operating Revenues:
Refined products . . . . . . . . . . . . . . . . . $ 169.7 134.8 323.3 254.1
Other, primarily crude oil resales and merchandise 37.8 31.4 69.3 62.4
--------- --------- --------- ---------
Gross Operating Revenues. . . . . . . . . . . . . $ 207.5 166.2 392.6 316.5
========= ========= ========= =========
Operating Profit (Loss):
Gross margin - refined products. . . . . . . . . . $ 18.9 15.2 34.0 38.7
Gross margin - other . . . . . . . . . . . . . . . 3.1 3.4 5.6 6.0
--------- --------- --------- ---------
Gross margin. . . . . . . . . . . . . . . . . . . 22.0 18.6 39.6 44.7
Operating expenses . . . . . . . . . . . . . . . . 21.5 20.7 40.7 40.6
Depreciation and amortization. . . . . . . . . . . 3.0 2.6 6.0 5.2
Other, including gain on asset sales . . . . . . . .2 .3 .2 ( 2.5)
--------- --------- --------- ---------
Operating Profit (Loss) . . . . . . . . . . . . . $ ( 2.7) ( 5.0) ( 7.3) 1.4
========= ========= ========= =========
Capital Expenditures . . . . . . . . . . . . . . . . $ 3.0 8.2 5.3 14.3
========= ========= ========= =========
Refining and Marketing - Total Product Sales
(average daily barrels)<F1>:
Gasoline . . . . . . . . . . . . . . . . . . . . . 26,996 21,596 25,172 22,080
Middle distillates . . . . . . . . . . . . . . . . 35,174 32,043 36,688 29,437
Heavy oils and residual product. . . . . . . . . . 16,103 13,070 14,966 14,748
--------- --------- --------- ---------
Total Product Sales . . . . . . . . . . . . . . . 78,273 66,709 76,826 66,265
========= ========= ========= =========
Refining and Marketing - Product Sales Prices
($/barrel):
Gasoline . . . . . . . . . . . . . . . . . . . . . $ 28.76 27.01 27.87 25.44
Middle distillates . . . . . . . . . . . . . . . . $ 24.72 23.48 24.18 23.85
Heavy oils and residual product. . . . . . . . . . $ 13.80 11.14 13.27 9.52
Refining and Marketing - Gross Margins on Total
Product Sales ($/barrel)<F1>:
Average sales price. . . . . . . . . . . . . . . . $ 23.87 22.20 23.27 21.19
Average cost of sales. . . . . . . . . . . . . . . 21.20 19.71 20.82 17.96
--------- --------- --------- ---------
Gross margin . . . . . . . . . . . . . . . . . . . $ 2.67 2.49 2.45 3.23
========= ========= ========= =========
Refinery Operations - Throughput
(average daily barrels) . . . . . . . . . . . . . 47,971 42,651 46,778 43,978
========= ========= ========= =========
Refinery Operations - Production
(average daily barrels):
Gasoline . . . . . . . . . . . . . . . . . . . . . 13,779 10,896 13,277 11,391
Middle distillates . . . . . . . . . . . . . . . . 19,426 18,014 19,556 17,975
Heavy oils and residual product. . . . . . . . . . 14,347 13,295 13,391 14,345
Refinery fuel. . . . . . . . . . . . . . . . . . . 1,969 1,929 1,998 1,834
--------- --------- --------- ---------
Total Refinery Production . . . . . . . . . . . . 49,521 44,134 48,222 45,545
========= ========= ========= =========
Refinery Operations - Product Spread ($/barrel)<F1>:
Yield value of products produced -
Gasoline . . . . . . . . . . . . . . . . . . . . $ 26.49 25.42 25.30 23.99
Middle distillates . . . . . . . . . . . . . . . $ 24.16 23.19 23.67 23.28
Heavy oils and residual product. . . . . . . . . $ 9.77 8.77 9.48 6.87
Average yield value of products produced . . . . . $ 20.70 19.48 20.22 18.39
Cost of raw materials. . . . . . . . . . . . . . . 17.87 16.34 17.33 14.28
--------- --------- --------- ---------
Product Spread. . . . . . . . . . . . . . . . . . $ 2.83 3.14 2.89 4.11
========= ========= ========= =========
12
<FN>
<F1> Total products sold include products manufactured at the refinery, existing
inventory balances and products purchased from third parties. Margins on
sales of purchased products, together with the effect of changes in
inventories, are included in the gross margin on total product sales
presented above. The Company's purchases of refined products for resale
approximated 28,700 and 22,000 average daily barrels for the 1995 and 1994
quarters, respectively, and 26,900 and 20,800 average daily barrels for the
1995 and 1994 periods, respectively. The product spread presented above
represents the excess of yield value of the products produced at the refinery
over the cost of the raw materials used to manufacture such products.
</TABLE>
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
While the refining industry market conditions strengthened as the 1995 quarter
advanced, margins on the Company's sales of refined products remained weak. The
Company's average feedstock costs increased to $17.87 per barrel for the 1995
quarter compared with $16.34 per barrel for the 1994 quarter, while the average
yield value of the Company's refinery production increased to $20.70 per barrel
for the 1995 quarter from $19.48 for the prior year quarter. As a result, the
Company's refinery spread remained depressed in the 1995 quarter and will
continue to be depressed as long as the cost of Alaska North Slope ("ANS") crude
oil remains high relative to the price received for the Company's sales of
refined products. The start-up in December 1994 of a vacuum unit at the
Company's refinery increased the yield of higher-valued products during the 1995
quarter and period and lessened the impact of these industry conditions on the
Company's refinery spread. In addition, margins on sales of inventories and
purchased volumes combined to improve the segment's gross margins as compared
with the prior year quarter.
Revenues from sales of refined products in the 1995 quarter were higher than the
1994 quarter due to higher sales prices and a 17% increase in sales volumes. In
addition, to optimize the refinery's feedstock mix and in response to market
conditions, the Company's resales of crude oil increased by $7.0 million. Costs
of sales, likewise, were higher in the 1995 quarter due to increased prices and
volumes. Depreciation and amortization increased $.4 million in the 1995
quarter due to capital additions, primarily the vacuum unit, completed in late
1994.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
The Company's average feedstock costs increased to $17.33 per barrel for the
1995 period compared with $14.28 per barrel for the 1994 period, while the
average yield value of the Company's refinery production increased to $20.22 per
barrel for the 1995 period from $18.39 for the prior year period. Increased
demand for ANS crude oil for use as a feedstock in West Coast refineries
combined with an oversupply of products in Alaska and on the West Coast resulted
in higher feedstock costs for the Company relative to increases in refined
product sales prices. As a result, the Company's refined product margins were
severely depressed in the 1995 period and will continue to be depressed as long
as the cost of ANS crude oil remains high relative to the price received for the
Company's sales of refined products.
Revenues from sales of refined products in the 1995 period were higher than the
1994 period due to higher sales prices and a 16% increase in sales volumes.
Resales of crude oil increased by $7.5 million. Costs of sales, likewise, were
higher in the 1995 period due to increased prices and volumes. Depreciation and
amortization increased $.8 million in the 1995 period due to capital additions,
primarily the vacuum unit, completed in late 1994. Included in the 1994 period
was a $2.4 million gain from the sale of assets.
13
<TABLE>
<CAPTION>
Exploration and Production Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions except per unit amounts)
<S> <C> <C> <C> <C>
United States:
Gross operating revenues<F1> . . . . . . . . . . $ 33.2 22.8 63.0 40.2
Lifting costs. . . . . . . . 5.4 3.2 10.2 5.5
Depreciation, depletion and amortization . . . . 8.1 4.7 16.7 8.5
Other . . . . . . . . . . . ( .3) .3 ( .5) .4
---------- --------- ---------- ---------
Operating Profit - United States . . . . . . . 20.0 14.6 36.6 25.8
---------- --------- ---------- ---------
Bolivia:
Gross operating revenues . . . . . . . . . . . . 3.2 3.3 5.8 6.1
Lifting costs. . . . . . . . . . . . . . . . . . .1 .1 .3 .3
Other . . . . . . . . . . . . . . . . . . . . . .8 .7 1.5 1.4
---------- --------- ---------- ---------
Operating Profit - Bolivia. . . . . . . . . . . 2.3 2.5 4.0 4.4
---------- --------- ---------- ---------
Total Operating Profit - Exploration
and Production . . . . . . . . . . . . . . . . . $ 22.3 17.1 40.6 30.2
========== ========= ========== =========
United States:
Capital expenditures . . . . . . . . . . . . . . $ 13.0 17.7 27.0 29.4
========== ========= ========== =========
Net natural gas production (average daily Mcf) -
Spot market and other . . . . . . . . . . . . . 121,811 51,003 101,157 41,960
Tennessee Gas Contract<F1>. . . . . . . . . . . 20,401 19,902 22,988 18,052
---------- --------- ---------- ---------
Total production . . . . . . . . . . . . . . . 142,212 70,905 124,145 60,012
========== ========= ========== =========
Average natural gas sales price per Mcf -. . . .
Spot market . . . . . . . . . . . . . . . . . . $ 1.52 1.74 1.48 1.84
Tennessee Gas Contract<F1>. . . . . . . . . . . $ 8.43 7.96 8.37 7.89
Average . . . . . . . . . . . . . . . . . . . . $ 2.51 3.49 2.75 3.66
Average lifting costs per Mcf<F2>. . . . . . . . $ .42 .49 .46 .51
Depletion per Mcf. . . . . . . . . . . . . . . . $ .62 .73 .74 .78
Bolivia:
Net natural gas production (average daily Mcf) . 19,715 22,050 18,321 20,601
Average natural gas sales price per Mcf. . . . . $ 1.30 1.20 1.28 1.21
Net crude oil (condensate) production
(average daily barrels) . . . . . . . . . . . . 610 735 581 699
Average crude oil price per barrel . . . . . . . $ 15.69 13.65 15.22 12.63
Average lifting costs per net equivalent Mcf . . $ .09 .03 .09 .07
<FN>
<F1> The Company is involved in litigation with Tennessee Gas relating to a
natural gas sales contract. See "Capital Resources and
Liquidity--Tennessee Gas Contract," "Legal Proceedings--Tennessee Gas
Contract" and Note 4 of Notes to Condensed Consolidated Financial
Statements.
<F2> Average lifting costs for the Company's U.S. operations include such items
as severance taxes, property taxes, insurance, materials and supplies and
transportation of natural gas production through Company-owned pipelines.
Since severance taxes are based upon sales prices of natural gas, the
average lifting costs presented above include the impact of above-market
prices for sales under the Tennessee Gas Contract. Lifting costs per Mcf
of natural gas sold in the spot market were approximately $.36 and $.40 for
the 1995 and 1994 quarters, respectively, and approximately $.38 and $.42
for the 1995 and 1994 periods, respectively.
</TABLE>
14
United States
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
The improvement in the 1995 quarter was attributable to the continued
development of the Bob West Field in South Texas. This success was indicated in
the Company's mid-year reserve report, prepared by the Company's independent
petroleum consultants, which reflected a 53% increase in the Company's domestic
proved reserves of natural gas from 129 Bcf of natural gas at December 31, 1994,
to 198 Bcf at June 30, 1995, after net production during this period of
approximately 23 Bcf. The pre-tax net present value of the Company's proved
reserves rose 10% to $198 million from $179 million at year-end 1994. Results
for the 1995 quarter benefited by nearly $4 million in the aggregate due to the
additions to proved reserves which reduced the domestic depletion rate to $.62
per Mcf, as compared with $.90 per Mcf for the 1995 first quarter. The number
of producing wells in South Texas in which the Company has a working interest
increased to 58 wells at the end of the 1995 quarter, compared with 38 wells at
the end of the 1994 quarter. The Company's 1995 quarter results included a 101%
increase in U.S. natural gas production with a $10.4 million increase in
revenues. Revenues for natural gas sales during the 1995 quarter, however, were
adversely affected by a 28% decline in the Company's weighted average sales
price, which included a 13% drop in average spot market prices. Total lifting
costs and depreciation, depletion and amortization were higher in the 1995
quarter, compared with the 1994 quarter, due to the increased production level,
but declined on a per Mcf basis.
Tennessee Gas may elect, and from time to time has elected, not to take gas
under the Tennessee Gas Contract. The Company recognizes revenues under the
Tennessee Gas Contract based on the quantity of natural gas actually taken by
Tennessee Gas. While Tennessee Gas has the right to elect not to take gas
during any contract year, this right is subject to an obligation to pay within
60 days after the end of such contract year for gas not taken. The contract
year ends on January 31 of each year. Although the failure to take gas could
adversely affect the Company's income and cash flows from operating activities
within a contract year, the Company should recover reduced cash flows shortly
after the end of the contract year under the take-or-pay provisions of the
Tennessee Gas Contract, subject to the provisions of a bond posted by Tennessee
Gas which is discussed in "Capital Resources and Liquidity--Tennessee Gas
Contract," "Legal Proceedings--Tennessee Gas Contract" and Note 4 of Notes to
Condensed Consolidated Financial Statements.
The Company has entered into a price swap with another company for approximately
8.25 Bcf of its anticipated U.S. natural gas production for the period April 1,
1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf.
For the three months and six months ended June 30, 1995, the Company's average
spot market sales prices, which included the effect of this price swap, were
$1.52 and $1.48 per Mcf, respectively.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
Results for the 1995 period included a 107% increase in U.S. natural gas
production with a $22.8 million increase in revenues. Revenues for natural gas
sales during the 1995 period, however, were adversely affected by a 25% decline
in the Company's weighted average sales price, which included a 20% drop in
average spot market prices. In response to the depressed spot market prices,
during the first quarter of the 1995 period the Company and one of its partners
initiated a voluntary reduction of natural gas production sold in the spot
market. The Company's share of this reduction was estimated to be approximately
30 Mmcf per day. In April 1995, the Company's U.S. natural gas production
levels resumed at higher rates. The Company may elect to curtail natural gas
production in the future, depending upon market conditions. Total lifting costs
and depreciation, depletion and amortization were higher in the 1995 period
compared with the 1994 period due to the increased production level, but
declined on a per Mcf basis. See discussion above for information relating to
additions to proved reserves and a price swap contract.
Bolivia
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
Operating results from the Company's Bolivian operations decreased by $.2
million during the 1995 quarter primarily due to an 11% decline in average daily
natural gas production, partially offset by an 8% increase in the average
natural gas sales price. During the 1994 quarter, the Company benefited from
higher levels of production due to the inability of another producer to satisfy
gas supply requirements. Also offsetting the decrease in production was a $2.04
per barrel increase in the average price of condensate production. The
Company's Bolivian natural gas production is sold to Yacimientos Petroliferos
Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas to
15
Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company based
in Argentina. During 1994, the contract between YPFB and YPF was extended
through March 31, 1997, maintaining approximately the same volumes as the
previous contract. Currently, the Company is selling its natural gas production
to YPFB based on the volume and pricing terms in the contract between YPFB and
YPF.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
Operating results from the Company's Bolivian operations decreased by $.4
million during the 1995 period, primarily due to an 11% decrease in production
of natural gas, partially offset by a 6% increase in natural gas prices. As
discussed above, the 1994 period benefited from higher production levels due to
the inability of another producer to satisfy gas supply requirements. Also
offsetting the decrease in production was a $2.59 per barrel increase in the
average price of condensate production. See discussion above for information
relating to the Company's contract with YPFB regarding sales of natural gas
production.
<TABLE>
<CAPTION>
Oil Field Supply and Distribution Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions)
<S> <C> <C> <C> <C>
Gross Operating Revenues . . . . . . . . . . . $ 21.2 18.3 38.4 36.9
Costs of Sales . . . . . . . . . . . . . . . . 18.3 15.8 33.4 31.7
-------- -------- -------- --------
Gross Margin . . . . . . . . . . . . . . . . 2.9 2.5 5.0 5.2
Operating Expenses and Other . . . . . . . . . 3.3 2.8 6.6 6.6
Depreciation and Amortization. . . . . . . . . .1 .1 .2 .2
-------- -------- -------- --------
Operating Loss . . . . . . . . . . . . . . . $ ( .5) ( .4) ( 1.8) ( 1.6)
======== ======== ======== ========
Refined Product Sales (average daily barrels) 8,419 7,486 7,679 7,455
======== ======== ======== ========
</TABLE>
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
Although sales volumes of refined products increased over 12%, gross margins
remained tight and were substantially offset by increased operating costs
resulting in a moderate increase in operating loss.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
Although refined product sales volumes increased during the 1995 period, gross
margin decreased primarily as a result of lower merchandise margins due to
continued strong competition in an oversupplied market. Included in operating
expenses in the 1994 period were charges of $1.2 million for discontinuing the
Company's environmental products marketing operations.
Interest Expense
The increases of $.8 million and $1.2 million in interest expense during the
1995 quarter and period, respectively, were primarily due to interest on the
vacuum unit financing and cash borrowings under the Revolving Credit Facility
during 1995 and to capitalized interest in 1994.
General and Administrative Expense
The increases of $.8 million and $1.0 million in general and administrative
expense during the 1995 quarter and period, respectively, were primarily due to
higher employee costs.
Other Expense
The decreases of $1.4 million and $1.9 million in other expense during the 1995
quarter and period, respectively, were largely attributable to lower
environmental expenses related to former operations.
16
Income Taxes
Income taxes of $1.4 million in the 1995 quarter compare with $.6 million in the
1994 quarter. The increase was primarily due to higher state income taxes on
the Company's increased taxable earnings.
IMPACT OF CHANGING PRICES
The Company's operating results and cash flows are sensitive to the volatile
changes in energy prices. Major shifts in the cost of crude oil and the price
of refined products can result in a change in gross margin from the refining and
marketing operations, as prices received for refined products may or may not
keep pace with changes in crude oil costs. These energy prices, together with
volume levels, also determine the carrying value of crude oil and refined
product inventory.
Likewise, major changes in natural gas prices impact revenues and the present
value of estimated future net revenues and cash flows from the Company's
exploration and production operations. The carrying value of oil and gas assets
may also be subject to noncash write-downs based on changes in natural gas
prices and other determining factors.
CAPITAL RESOURCES AND LIQUIDITY
The Company operates in an environment where markets for crude oil, natural gas
and refined products historically have been volatile and are likely to continue
to be volatile in the future. The Company's liquidity and capital resources are
significantly impacted by changes in the supply of and demand for crude oil,
natural gas and refined petroleum products, market uncertainty and a variety of
additional factors that are beyond the control of the Company. These factors
include, among others, the level of consumer product demand, weather conditions,
the proximity of the Company's natural gas reserves to pipelines, the capacities
of such pipelines, fluctuations in seasonal demand, governmental regulations,
the price and availability of alternative fuels and overall economic conditions.
The Company cannot predict the future markets and prices for its natural gas or
refined products and the resulting future impact on earnings and cash flows.
The Company's operations have been adversely affected by depressed market
conditions and will continue to be adversely affected for so long as these
market conditions exist. The Company's future capital expenditures, borrowings
under its credit arrangements and other sources of capital will be affected by
these conditions.
The Company continues to assess its existing asset base in order to maximize
returns and financial flexibility through diversification, acquisitions and
divestitures in all of its operating segments. This ongoing assessment
includes, in the Exploration and Production segment, evaluating ways in which
the Company might diversify the mix of its oil and gas assets, reduce the asset
concentration associated with the Bob West Field and lower future capital
commitments. In these regards, the Company is evaluating offers to sell or
exchange approximately 40% of its total proved domestic natural gas reserves in
the Bob West Field. The proved reserves for which offers are being evaluated
are located in the C, D, E and F units of the Bob West Field and do not include
acreage covered by the Tennessee Gas Contract (see Note 4 of Notes to Condensed
Consolidated Financial Statements). No offer for a sale or exchange has been
accepted and there is no assurance that a sale or exchange will be consummated.
The Company is uncertain as to the impact of these initiatives upon its capital
resources and liquidity, if any.
In July 1995, the Company completed the Longoria #1 exploratory well in Webb
County of South Texas, marking the discovery of a new natural gas field. This
well tested at an initial gross rate of 3.5 Mmcf per day of natural gas. Tesoro
serves as operator of this well with a 45% working interest and a 33.33% net
revenue interest. The discovery was made on Tesoro's 2,200-acre S. Guerra
prospect. Initial estimates are that this new field is analogous to the Guerra
field (four miles to the northeast), which remains under development but has
already produced a cumulative 125 Bcf of natural gas. Additional tests
currently are being conducted on the Longoria #1 to determine the producing
zone's permeability and the need to fracture the pay sands to stimulate higher
production rates. The well will remain shut-in until such tests are completed
and the well can be tied in to one of several pipelines in the area. The
Company is uncertain as to the future impact of this discovery upon its capital
resources and liquidity.
17
Credit Arrangements
The Company has financing and credit arrangements under a three-year, $125
million corporate Revolving Credit Facility dated April 20, 1994 with a
consortium of ten banks. The Revolving Credit Facility, which is subject to a
borrowing base, provides for (i) the issuance of letters of credit up to the
full amount of the borrowing base and (ii) cash borrowings up to the amount of
the borrowing base attributable to domestic oil and gas reserves. Outstanding
obligations under the Revolving Credit Facility are secured by liens on
substantially all of the Company's trade accounts receivable and product
inventory and by mortgages on the Company's refinery and South Texas natural gas
reserves. At June 30, 1995, the borrowing base of approximately $111 million
included a domestic oil and gas reserve component of $45 million. At June 30,
1995, the Company had outstanding letters of credit under the Revolving Credit
Facility of approximately $51 million with no cash borrowings outstanding. The
Company has borrowed from time to time under this facility during 1995 on a
short-term basis to finance working capital requirements and capital
expenditures.
Under the terms of the Revolving Credit Facility, as amended, the Company is
required to maintain specified levels of working capital, tangible net worth,
consolidated cash flow and refinery cash flow, as defined. Among other matters,
the Revolving Credit Facility contains certain restrictions with respect to (i)
capital expenditures, (ii) incurrence of additional indebtedness, and (iii)
dividends on capital stock. The Revolving Credit Facility contains other
covenants customary in credit arrangements of this kind. At June 30, 1995, the
Company did not satisfy the refinery cash flow requirement which required the
Company to obtain a waiver to the Revolving Credit Facility. Compliance with
certain financial covenants under the Revolving Credit Facility is primarily
dependent on the Company's maintenance of specified levels of cash flows from
operations, capital expenditures, levels of borrowings and the value of the
Company's domestic oil and gas reserves. Based on current depressed refinery
margins, the Company will be required to seek a waiver or an amendment to the
Revolving Credit Facility from its banks with respect to its refinery cash flow
requirement for the remainder of 1995. The Company believes it will be able to
negotiate terms and conditions with its banks under the Revolving Credit
Facility which will allow the Company to adequately finance its operations. See
Note 3 of Notes to Condensed Consolidated Financial Statements.
Debt Obligations
The Company's funded debt obligations as of June 30, 1995 included approximately
$64.6 million principal amount of 12-3/4% Subordinated Debentures ("Subordinated
Debentures"), which bear interest at 12-3/4% per annum and require sinking fund
payments sufficient to annually retire $11.25 million principal amount of
Subordinated Debentures. As part of a recapitalization in 1994, $44.1 million
principal amount of Subordinated Debentures was tendered in exchange for a like
principal amount of new 13% Exchange Notes ("Exchange Notes"). This exchange
satisfied the 1994 sinking fund requirement and, except for $.9 million, will
satisfy sinking fund requirements for the Subordinated Debentures through 1997.
The indenture governing the Subordinated Debentures contains certain covenants,
including a restriction that prevents the current payment of cash dividends on
Common Stock and currently limits the Company's ability to purchase or redeem
any shares of its capital stock. The Exchange Notes bear interest at 13% per
annum, mature December 1, 2000 and have no sinking fund requirements. The
limitation on dividend payments included in the indenture governing the Exchange
Notes is less restrictive than the limitation imposed by the Subordinated
Debentures. The Subordinated Debentures and Exchange Notes are redeemable at
the option of the Company at 100% of principal amount, plus accrued interest.
The Company continuously reviews financing alternatives with respect to its
Subordinated Debentures and Exchange Notes. However, there can be no assurance
whether or when the Company would propose a refinancing, if any.
Capital Expenditures
The Company has under consideration total capital expenditures for 1995 of
approximately $60 million, compared with $100 million for 1994. Capital
expenditures for the continued development of the Bob West Field and exploratory
drilling in other areas of South Texas in 1995 are projected to be $47 million.
The amount of such expenditures for exploration and production activities is
dependent upon, among other factors, the price the Company receives for its
natural gas production. Capital expenditures for 1995 for the refining and
marketing segment are projected to be $11 million, primarily for capital
improvements at the refinery and expansion of the Company's retail locations in
Alaska. For the six months ended June 30, 1995, total capital expenditures
amounted to $33 million, including $27 million for exploration and production
and $5 million for refining and
18
marketing, which were funded through cash flows from operations, existing cash
and borrowings under the Revolving Credit Facility. The Company expects to
finance capital expenditures for the remainder of 1995 through a combination of
cash flows from operations and borrowings under the Revolving Credit Facility.
Cash Flows
At June 30, 1995, the Company's net working capital totaled $83.0 million, which
included cash of $7.4 million and a receivable from Tennessee Gas of $35.4
million. For information on litigation related to a natural gas sales contract
and the related impact on the Company's cash flows from operations, see
"Tennessee Gas Contract" below and Note 4 of Notes to Condensed Consolidated
Financial Statements.
Components of the Company's cash flows are set forth below (in millions):
Six Months Ended
June 30,
-----------------------
1995 1994
------ ------
Cash Flows From (Used In):
Operating Activities . . . . . . . . . . . . . . . $ 29.4 45.0
Investing Activities . . . . . . . . . . . . . . . (34.9) (34.8)
Financing Activities . . . . . . . . . . . . . . . ( 1.2) ( 5.5)
------ ------
Increase (Decrease) in Cash and Cash Equivalents . . $ ( 6.7) 4.7
====== ======
Net cash from operating activities of $29.4 million during the 1995 period
compares to $45.0 million for the 1994 period. Although natural gas production
from the Bob West Field increased during the 1995 period, lower cash receipts
for sales of natural gas and reduced cash flows from the refining and marketing
operations adversely affected the Company's cash flows from operations. Net
cash used in investing activities of $34.9 million included $32.8 million of
capital expenditures and $3.0 million for acquisition of the Kenai Pipe Line
Company. Capital expenditures for the 1995 period included $27.0 million for
the Company's exploration and production activities in South Texas, primarily
for completion of nine natural gas development wells. Net cash used in
financing activities of $1.2 million during the 1995 period was primarily
related to payments of long-term debt. The Company's gross borrowings and
repayments under its Revolving Credit Facility totaled $159.5 million during the
1995 period.
Tennessee Gas Contract
The Company is selling a portion of the gas from its Bob West Field to Tennessee
Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement
("Tennessee Gas Contract") which provides that the price of gas shall be the
maximum price as calculated in accordance with Section 102(b)(2) ("Contract
Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990,
Tennessee Gas filed suit against the Company in the District Court of Bexar
County, Texas, alleging that the Tennessee Gas Contract is not applicable to the
Company's properties and that the gas sales price should be the price calculated
under the provisions of Section 101 of the NGPA rather than the Contract Price.
During June 1995, the Contract Price was in excess of $8.00 per Mcf, the Section
101 price was $4.94 per Mcf and the average spot market price was $1.56 per Mcf.
Tennessee Gas also claimed that the contract should be considered an "output
contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and
that the increases in volumes tendered under the contract exceeded those
allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of
19
Texas heard arguments in December 1994, regarding the output contract issue and
certain of the issues raised by Tennessee Gas. On August 1, 1995, the Supreme
Court of Texas, in a divided opinion, affirmed the decision of the appellate
court on all issues, determined that the Tennessee Gas Contract was an output
contract and remanded the case to the trial court for determination of whether
gas volumes tendered by the Company to Tennessee Gas were tendered in good faith
and were not unreasonably disproportionate to any normal or otherwise comparable
prior output or stated estimates in accordance with Section 2.306 of the UCC.
In addition, the Supreme Court affirmed that the price under the Tennessee Gas
Contract is the Contract Price. The Company intends to file a motion for
rehearing before the Texas Supreme Court on the issue of whether the Tennessee
Gas Contract is an output contract. Through June 30, 1995, under the Tennessee
Gas Contract, the Company recognized cumulative revenues in excess of spot
market prices through September 17, 1994, and in excess of a nonrefundable $3.00
per Mcf bond price subsequent to September 17, 1994, totaling $86.6 million of
which $33.9 million is included in receivables. The Company and its outside
counsel are evaluating the impact of various aspects of the Supreme Court
decision. The Company believes that, if this issue is tried, the gas volumes
tendered to Tennessee Gas will be found to have been in good faith and otherwise
in accordance with the requirements of the UCC. However, there can be no
assurance as to the ultimate outcome at trial. An adverse outcome of this
litigation could require the Company to reverse some or all of the incremental
revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts
received above spot market prices, plus interest if awarded by the court.
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995 a
hearing was held before the trial court regarding the extension of the Tennessee
Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the
period August 14, 1995, until the earlier of October 16, 1995, or the date the
Supreme Court issues its rulings on motions for rehearing, (i) continue to take
at least its entire take-or-pay volume obligation, (ii) pay for gas at a price
of $3.00 per Mmbtu subject to potential refund of amounts in excess of market
prices if Tennessee Gas should ultimately prevail in the litigation, and (iii)
post a $25 million bond in addition to the $120 million bond presently in place.
Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond
Price until August 14, 1995.
Environmental and Other Matters
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which change frequently, regulate the discharge of
materials into the environment and may require the Company to remove or mitigate
the environmental effects of the disposal or release of petroleum or chemical
substances at various sites or install additional controls or other
modifications or changes in use for certain emission sources. The Company is
currently involved in remedial responses and has incurred cleanup expenditures
associated with environmental matters at a number of sites, including certain of
its own properties. In addition, the Company is holding discussions with the
Department of Justice concerning the assessment of penalties with respect to
certain alleged violations of the Clean Air Act. At June 30, 1995 the Company's
accruals for environmental matters, including the alleged violations of the
Clean Air Act, amounted to $11.3 million. Also included in this amount is an
approximate $4 million noncurrent liability for remediation of the KPL
properties, which liability has been funded by the former owners of KPL through
a restricted escrow deposit. Based on currently available information,
including the participation of other parties or former owners in remediation
actions, the Company believes these accruals are adequate. In addition, to
comply with environmental laws and regulations, the Company anticipates that it
will be required to make capital improvements in 1995 of approximately $2
million, primarily for the removal and upgrading of underground storage tanks,
and approximately $8 million during 1996 for the installation of dike liners
required under Alaska environmental regulations. Conditions that require
additional expenditures may exist for various Company sites, including, but not
limited to, the Company's refinery, retail gasoline outlets (current and closed
locations) and petroleum product terminals, and for compliance with the Clean
Air Act. The amount of such future expenditures cannot currently be determined
by the Company. For
20
further information on environmental contingencies, see Note 4 of Notes to
Condensed Consolidated Financial Statements.
The Company's contract with the State of Alaska ("State") for the purchase of
royalty crude oil expires on December 31, 1995. In May 1995, the Company
renegotiated a new three-year contract with the State for the period January 1,
1996 through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of ANS royalty crude oil, the primary
feedstock for the Company's refinery, and is priced at the weighted average
price reported to the State by a major North Slope producer for ANS crude oil as
valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this
agreement, the Company is required to utilize in its refinery operations volumes
equal to at least 80% of the ANS crude oil to be purchased from the State. This
contract contains provisions that allow the Company to temporarily or
permanently reduce its purchase obligations.
As discussed in Note 4 of Notes to Condensed Consolidated Financial Statements,
the Company is involved with other litigation and claims, none of which is
expected to have a material adverse effect on the financial condition of the
Company.
21
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Tennessee Gas Contract. The Company is selling a portion of the gas from its
Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas
Purchase and Sales Agreement ("Tennessee Gas Contract") which provides that the
price of gas shall be the maximum price as calculated in accordance with Section
102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In
August 1990, Tennessee Gas filed suit against the Company in the District Court
of Bexar County, Texas, alleging that the Tennessee Gas Contract is not
applicable to the Company's properties and that the gas sales price should be
the price calculated under the provisions of Section 101 of the NGPA rather than
the Contract Price. During June 1995, the Contract Price was in excess of $8.00
per Mcf, the Section 101 price was $4.94 per Mcf and the average spot market
price was $1.56 per Mcf. Tennessee Gas also claimed that the contract should be
considered an "output contract" under Section 2.306 of the Texas Uniform
Commercial Code ("UCC") and that the increases in volumes tendered under the
contract exceeded those allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of Texas heard arguments in December 1994, regarding the output contract
issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the
Supreme Court of Texas, in a divided opinion, affirmed the decision of the
appellate court on all issues, determined that the Tennessee Gas Contract was an
output contract and remanded the case to the trial court for determination of
whether gas volumes tendered by the Company to Tennessee Gas were tendered in
good faith and were not unreasonably disproportionate to any normal or otherwise
comparable prior output or stated estimates in accordance with Section 2.306 of
the UCC. In addition, the Supreme Court affirmed that the price under the
Tennessee Gas Contract is the Contract Price. The Company intends to file a
motion for rehearing before the Texas Supreme Court on the issue of whether the
Tennessee Gas Contract is an output contract. Through June 30, 1995, under the
Tennessee Gas Contract, the Company recognized cumulative revenues in excess of
spot market prices through September 17, 1994, and in excess of a nonrefundable
$3.00 per Mcf bond price subsequent to September 17, 1994, totaling $86.6
million of which $33.9 million is included in receivables. The Company and its
outside counsel are evaluating the impact of various aspects of the Supreme
Court decision. The Company believes that, if this issue is tried, the gas
volumes tendered to Tennessee Gas will be found to have been in good faith and
otherwise in accordance with the requirements of the UCC. However, there can be
no assurance as to the ultimate outcome at trial. An adverse outcome of this
litigation could require the Company to reverse some or all of the incremental
revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts
received above spot market prices, plus interest if awarded by the court.
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995, a
hearing was held before the trial court regarding the extension of the Tennessee
Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the
period August 14, 1995, until the earlier of October 16, 1995, or the date the
Supreme Court issues its rulings on motions for rehearing, (i) continue to take
at least its entire take-or-pay volume obligation, (ii) pay for gas at a price
of $3.00 per Mmbtu subject to potential refund of amounts in excess of market
prices if Tennessee Gas should ultimately prevail in litigation, and (iii) post
a $25 million bond in addition to the $120 million bond presently in place.
Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond
Price until August 14, 1995.
22
Environmental Matters. As previously reported, the Company has been identified
by the Environmental Protection Agency ("EPA") as a potentially responsible
party ("PRP") pursuant to the Comprehensive Environmental Response,
Compensation, and Liability Act of 1980 ("CERCLA") for the Hansen Container
Site, Grand Junction, Mesa County, Colorado ("Site"). The Site was a drum
recycling site which accepted and recycled used containers from the mid-1960's
through 1989. Over 220 parties have been identified as PRP's at the Site. The
Company sold a minimum number of containers to the Site in the mid-1970's.
CERCLA imposes joint and several liability on PRP's; each PRP is therefore
responsible for 100% of the costs of the response actions necessary to remediate
the Site in the event a settlement with the EPA cannot be reached. The EPA has
spent approximately $2.35 million at the Site through September 1994 and is
seeking reimbursement from over 220 PRP's. The Company has entered into an
Administrative Order on Consent for De Minimis Settlement with the EPA
applicable to those PRP's who each contributed less than 2% of the total
contamination at the Site. The Company has agreed to contribute approximately
$1,400 in full settlement of claims against the Company.
As previously reported, in March 1992, the Company received a Compliance Order
and Notice of Violation from the EPA alleging violations by the Company of the
New Source Performance Standards under the Clean Air Act at its Alaska refinery.
These allegations include failure to install, maintain and operate monitoring
equipment over a period of approximately six years, failure to perform accuracy
testing on monitoring equipment, and failure to install certain pollution
control equipment. From March 1992 to July 1993, the EPA and the Company
exchanged information relevant to these allegations. In addition, the EPA
conducted an environmental audit of the Company's refinery in May 1992. As a
result of this audit, the EPA is also alleging violation of certain regulations
related to asbestos materials. In October 1993, the EPA referred these matters
to the Department of Justice ("DOJ"). The DOJ contacted the Company to begin
negotiating a resolution of these matters. The DOJ has indicated that it is
willing to enter into a judicial consent decree with the Company and that this
decree would include a penalty assessment. Negotiations on the penalty are in
progress. The DOJ has currently proposed a penalty assessment of approximately
$2.3 million. The Company is continuing to negotiate with the DOJ but cannot
predict the ultimate outcome of the negotiations.
Refund Claim. As previously reported, in July 1994, Simmons Oil Corporation,
also known as David Christopher Corporation, a former customer of the Company
("Customer"), filed suit against the Company in the United States District Court
for the District of New Mexico for a refund in the amount of approximately $1.2
million, plus interest of approximately $4.4 million and attorney's fees,
related to a gasoline purchase from the Company in 1979. The Customer also
alleges entitlement to treble damages and punitive damages in the aggregate
amount of $16.8 million. The refund claim is based on allegations that the
Company renegotiated the acquisition price of gasoline sold to the Customer and
failed to pass on the benefit of the renegotiated price to the Customer in
violation of Department of Energy price and allocation controls then in effect.
In May 1995, the court issued an order granting the Company's motion for summary
judgment and dismissed with prejudice all the claims in the Customer's
complaint. In June 1995, the Customer filed a notice of appeal with the U.S.
Court of Appeals for the Federal Circuit. The Company cannot predict the
ultimate resolution of this matter but believes the claim is without merit.
23
Item 4. Submission of Matters to a Vote of Security Holders
(a) The 1995 annual meeting of stockholders of the Company was held on May
4, 1995.
(b) The names of the directors elected at the meeting and a tabulation of
the number of votes cast for, against or withheld with respect to each
such director are set forth below:
Name Votes Votes Votes
For Against Withheld
Michael D. Burke 21,058,262 0 946,368
Robert J. Caverly 12,649,742 0 9,354,888
Peter M. Detwiler 11,118,264 0 10,886,366
Steven H. Grapstein 21,041,619 0 963,011
Raymond K. Mason, Sr. 11,112,707 0 10,891,923
John J. McKetta, Jr. 11,085,270 0 10,919,360
Joel V. Staff 13,377,871 0 8,626,759
Murray L. Weidenbaum 12,653,329 0 9,351,301
At the annual meeting of stockholders, a dissident slate of directors
consisting of six individuals was nominated from the floor. The
dissident slate subsequently challenged the results of the election.
The challenge was rejected by the inspector of election and,
thereafter, by the Delaware Chancery Court which upheld the votes set
forth above.
Joel V. Staff resigned as a director of the Company effective June 13,
1995.
Bruce A. Smith was elected as a director of the Company effective July
26, 1995.
(c) A brief description of each matter, other than the election of
directors, voted upon at the meeting and the number of votes cast for,
against or withheld, as well as the number of abstentions and broker
non-votes as to each matter, is set forth below:
With respect to a proposal to approve and adopt the 1995 Non-Employee
Director Stock Option Plan, there were 10,957,145 votes for; 10,403,943
votes against; 284,496 votes withheld; 359,046 broker non-votes; and no
abstentions.
With respect to a proposal to limit the number of shares which can be
granted to any single participant in one year under the Executive
Long-Term Incentive Plan, there were 12,198,512 votes for; 9,287,131
votes against; 163,941 votes withheld; 355,046 broker non-votes; and no
abstentions.
With respect to a proposal to appoint Deloitte & Touche LLP as
independent auditors for the Company for fiscal year 1995, there were
21,235,489 votes for; 256,468 votes against; 157,627 votes withheld;
355,046 broker non-votes; and no abstentions.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
See the Exhibit Index immediately preceding the exhibits filed
herewith.
(b) Reports on Form 8-K
No reports on Form 8-K have been filed during the quarter for which
this report is filed.
24
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TESORO PETROLEUM CORPORATION
Registrant
Date: August 14, 1995 /s/ Michael D. Burke
Michael D. Burke
President and
Chief Executive Officer
Date: August 14, 1995 /s/ Bruce A. Smith
Bruce A. Smith
Chief Operating Officer,
Executive Vice President and
Chief Financial Officer
25
EXHIBIT INDEX
Exhibit
Number
4 Copy of Consent and Waiver No. 2 dated as of July 31, 1995 to the
Company's Credit Agreement dated as of April 20, 1994.
10 Agreement for the Sale and Purchase of State Royalty Oil dated as of
April 21, 1995 by and between Tesoro Alaska Petroleum Company and the
State of Alaska.
11 Information Supporting Earnings (Loss) Per Share Computations.
27 Financial Data Schedule.
26
CONSENT AND WAIVER NO. 2
CONSENT AND WAIVER NO. 2 (the "Consent and Waiver"), dated as of July
31, 1995, by and among Tesoro Petroleum Corporation (the "Company"), Texas
Commerce Bank National Association ("TCB"), individually, as an Issuing Bank and
as Agent (the "Agent"), Banque Paribas ("BP"), individually, as an Issuing Bank
and as Co-Agent, and Bank of Scotland, Christiania Bank, The Bank of Nova
Scotia, NBD Bank, Bank of America Illinois, First Union National Bank of North
Carolina, National Bank of Canada and The Frost National Bank.
WITNESSETH
WHEREAS, the Company has entered into a Credit Agreement, dated as of
April 20,1994, among the Company, TCB, individually, as an Issuing Bank and as
Agent, BP, individually, as an Issuing Bank and as Co-Agent, and the other
financial institutions parties thereto (the "Credit Agreement"; all capitalized
terms used herein and not otherwise defined herein shall have the meanings
ascribed thereto in the Credit Agreement);
WHEREAS, the Company has requested that Majority Lenders consent to the
waiver of the Company's obligation to cause the Tesoro Refining and Marketing
Group to maintain the Tesoro Refining and Marketing Group EBITDA for the Rolling
Period ending on June 30,1995;
WHEREAS, the Agent, the Issuing Banks and the Lenders are willing to
agree to the consent and waiver contained herein upon the terms and conditions
set forth below;
NOW, THEREFORE, the parties hereto agree as follows:
SECTION 1. Consent and Waiver. The Majority Lenders hereby consent to
the waiver of the Company's obligations under Section 5.03(d) to the Credit
Agreement to cause the Tesoro Refining and Marketing Group to maintain the
Tesoro Refining and Marketing Group EBITDA of at least $15,000,000 for the
Rolling Period ending on June 30, 1995; provided, however, the Company agrees
that it will be required to comply in full with such Section 5.03(d) of the
Credit Agreement for the Rolling Period ending on September 30,1995.
SECTION 2. Representations and Warranties. On and as of the date
hereof, after giving effect to this Consent and Waiver, the Company represents
and warrants the following:
(a) all of the representations and warranties in Article IV of the
Credit Agreement are true and correct in all material respects as if made on and
as of the date of this Consent and Waiver, except to the extent any such
representation or warranty relates specifically to an earlier date;
(b) no Default or Event of Default has occurred and is continuing, or
would result from the effectiveness of this Consent and Waiver; and
(c) The execution and delivery by the Company of this Consent and Waiver
are within the Company's powers and have been duly authorized by all necessary
corporate or other action.
SECTION 3. Effect on Credit Apreement. Except to the extent of the
consents and waivers specifically set forth herein, all provisions of the Credit
Agreement and the other Security Instruments are and shall remain in full force
and effect and are hereby ratified and confirmed in all respects, and the
execution, delivery and effectiveness of this Consent and Waiver shall not
operate as a waiver of any provision of the Credit Agreement or any other
Security Instrument not specifically referred to herein.
SECTION 4. Execution in Counterparts. This Consent and Waiver may be
executed in any number of counterparts, and by the parties hereto in separate
counterparts, each of which when so executed shall be deemed to be an original
and all of which taken together shall constitute one and the same agreement.
SECTION 5. GOVERNING LAW. THIS CONSENT AND WAIVER SHALL BE GOVERNED BY
AND CONSTRUED IN ACCORDANCE WITH THE APPLICABLE LAWS OF THE STATE OF TEXAS
WITHOUT REFERENCE TO PRINCIPLES OF CONFLICT OF LAWS.
SECTION 6. Previous Agreements. This Consent and Waiver supersedes any
and all previous agreements, documents and understandings relating to the
consents and waivers set forth herein, to the extent inconsistent herewith.
IN WITNESS WHEREOF, the parties hereto have caused this Consent and
Waiver to be duly executed and delivered by their respective officers or other
duly authorized representatives as of the date first above written.
COMPANY:
TESORO PETROLEUM CORPORATION
By: /s/ William T. Van Kleef
Name: William T. Van Kleef
Title: Vice President, Treasurer
-2-
AGENT, ISSUING BANKS AND LENDERS:
TEXAS COMMERCE BANK NATIONAL
ASSOCIATION, individually, as an Issuing
Bank and as Agent
By: /s/ D. G. Mills
Name: D. G. Mills
Title: Vice President
-3 -
BANQUE PARIBAS, individually, as an
Issuing Bank and as Co-Agent
By: /s/ Brian Malone
Name: BRIAN MALONE
Title: VICE PRESIDENT
By: /s/ Barton D. Schouest
Name: Barton D. Schouest
Title: Group Vice President
-4-
BANK OF SCOTLAND
By: /s/ Catherine M. Oniffrey
Name: CATHERINE M. ONIFFREY
Title: VICE PRESIDENT
-5-
CHRISTIANIA BANK
By: /s/ Peter M. Dodge
Name: PETER M. DODGE
Title: VICE PRESIDENT
By: /s/ Debra Ives
Name: DEBRA IVES
Title: VICE PRESIDENT
-6-
THE BANK OF NOVA SCOTIA
By: /s/ F. C. H. Ashby
Name: F.C.H. Ashby
Title: Senior Manager Loan Operations
-7-
NBD BANK
By: /s/ Russell H. Liebetrau, Jr.
Name: RUSSELL H. LIEBETRAU, JR.
Title: Vice President
-8-
BANK OF AMERICA ILLINOIS
By: /s/ Ronald E. McKaig
Name: Ronald E. McKaig
Title: Vice President
-9-
FIRST UNION NATIONAL BANK OF NORTH
CAROLINA
By: /s/ Michael J. Kolosowsky
Name: Michael J. Kolosowsky
Title: Vice President
-10-
NATIONAL BANK OF CANADA
By: /s/ Larry L. Sears
Name: Larry L. Sears
Title: Group Vice President
By: /s/ Douglas G. Clark
Name: Douglas G. Clark
Title: Vice President
-11-
THE FROST NATIONAL BANK
By: /s/ Phil Dudley
Name: Phil Dudley
Title: Vice President
-12-
AGREEMENT FOR THE SALE AND PURCHASE
OF
STATE ROYALTY OIL
to
TESORO ALASKA PETROLEUM COMPANY
THE STATE OF ALASKA
Department of Natural Resources
Dated as of April 21, 1995
TABLE OF CONTENTS
ARTICLE I
DEFINITIONS.................................................1
1.1 Commissioner ......................................1
1.2 Daily Royalty Oil..................................1
1.3 Day................................................1
1.4 Effective Date ....................................1
1.5 Field Cost Agreement. .............................1
1.6 Leases.............................................1
1.7 Lessee ............................................2
1.8 Month .............................................2
1.9 Oil................................................2
1.10 Point of Delivery .................................2
1.11 Royalty Oil........................................2
1.12 Royalty Settlement Agreements .....................2
1.13 Royalty Value .....................................2
1.14 TAPS ..............................................2
1.15 Unit Agreement.....................................2
ARTICLE II
SALE OF ROYALTY OIL ........................................3
2.1 Quantity...........................................3
2.2 Quality............................................4
2.3 Price of the Royalty Oil...........................5
2.4 Reopeners..........................................5
2.5 Point and Time of Delivery.........................7
2.6 Passage of Title and Risk of Loss..................7
2.7 Tesoro's Responsibility............................7
2.8 Transportation Arrangements .......................7
2.9 Absolute Obligations...............................8
2.10 Date of First Delivery.............................8
2.11 Performance Guaranty and Reservation Fee...........8
2.12 In-State Processing................................8
ARTICLE III
REPRESENTATION AND OBLIGATIONS OF TESORO....................9
3.1 Good Standing and Due Authorization................9
3.2 Financial Condition...............................10
3.3 Financial Statements .............................10
ii
ARTICLE IV
MEASUREMENTS AND TESTS ....................................11
ARTICLE V
PAYMENTS AND ACCOUNTING....................................11
5.1 Initial Billing...................................11
5.2 Initial Adjustment ...............................12
5.3 Subsequent Adjustments ...........................13
5.4 Payment...........................................13
5.5 Interest..........................................14
5.6 Late Payment Penalty..............................15
5.7 Payment to Lessee.................................16
5.8 Payment to Third Parties..........................16
ARTICLE VI
TERM ......................................................16
ARTICLE VII
DEFAULT OR TERMINATION.....................................17
7.1 Default...........................................17
7.2 Failure to Pay Debts..............................18
7.3 State's Remedies..................................19
7.4 Tesoro's Exclusive Remedies.......................20
ARTICLE VIII
DISPOSITION OF OIL.........................................20
8.1 Disposition of Oil Upon Default or Termination ...20
8.2 Inability to Receive Oil..........................20
8.3 No Right to Storage or Underlift .................21
ARTICLE IX
WAIVER.....................................................21
ARTICLE X
VALIDITY...................................................22
ARTICLE XI
FORCE MAJEURE AND CHANGE IN CONDITION......................22
11.1 Effect of Force Majeure ..........................22
11.2 Responsibility....................................22
iii
ARTICLE XII
NOTICES....................................................23
12.1 Method............................................23
12.2 Change of Address ................................24
ARTICLE XIII
RULES AND REGULATIONS......................................24
ARTICLE XIV
SOVEREIGN POWER OF THE STATE...............................24
ARTICLE XV
SECURITY...................................................24
15.1 Letter of Credit..................................24
15.2 Reduction of Term.................................26
ARTICLE XVI
PREFERENTIAL HIRING AND NON-DISCRIMINATION ................26
ARTICLE XVII ...................................................27
APPLICABLE LAW.............................................27
17.1 Alaska Law........................................27
17.2 Submission to Jurisdiction........................27
ARTICLE XVIII
WARRANTIES.................................................27
ARTICLE XIX
AMENDMENT..................................................28
ARTICLE XX
SUCCESSORS AND ASSIGNS.....................................28
ARTICLE XXI
HEADINGS ..................................................28
ARTICLE XXII
RECORDS....................................................28
22.1 Preservation of Records ..........................28
22.2 Inspection of Records of Parties..................29
ARTICLE XXIII
INTERPRETATION OF TERMS AND CONDITIONS ....................30
iv
ARTICLE XXIV
COUNTERPARTS ..............................................30
SIGNATURES......................................................31
ACKNOWLEDGEMENT ................................................32
EXHIBIT A.......................................................35
v
AGREEMENT FOR THE SALE AND
PURCHASE OF ROYALTY OIL
THIS AGREEMENT is effective as of April 21, 1995 by and between the State
of Alaska (State) and Tesoro Alaska Petroleum Company, a Delaware corporation
with its principal offices located at 3230 C Street, Anchorage, Alaska 99503 and
Tesoro Petroleum Corporation, a Delaware corporation with its principal offices
located at 8700 Tesoro Drive, San Antonio, Texas 78217 (collectively Tesoro).
ARTICLE I
DEFINITIONS
As used in this Agreement, the following terms shall have the following
respective meanings:
1.1 "Commissioner" means the Commissioner of the Alaska Department
of Natural Resources or his designee.
1.2 "Daily Royalty Oil" means the quantity of Royalty Oil produced
by the Lessees from the Prudhoe Bay Unit Area in a Day except as provided in
Article 2.1 (b).
1.3 "Day" means a period of twenty-four (24) consecutive hours,
beginning at 12:01 a.m., Alaska Standard Time.
1.4 "Effective Date" shall have the meaning set out in Article VI.
1.5 "Field Cost Agreement" means the Prudhoe Bay Royalty Settlement
Agreement effective April 1, 1980.
1.6 "Leases" means the Oil and Gas leases which are subject to the
terms of the Prudhoe Bay Unit Agreement.
1
1.7 "Lessee" means any person owning a working interest in any of
the Leases.
1.8 "Month" means the period beginning at 12:01 a.m., Alaska
Standard Time, on the first Day of the calendar Month and ending at the same
time on the first Day of the next succeeding calendar Month.
1.9 "Oil" means the same as the word "oil" under the Leases and the
Unit Agreement, except where inconsistent with Articles 2.1(b) and 2.2 of this
Agreement, in which case Articles 2.1(b) and 2.2 shall control. For purposes of
this Agreement, "Oil" shall also include natural gas liquids ("NGLs").
1.10 "Point of Delivery" shall have the meaning set out in Article
2.6.
1.11 "Royalty Oil" means the Oil which the State may take in-kind
(in amount) as its royalty under the Leases whether or not the State has elected
to take or is taking that royalty in-kind except as provided in Article 2.1(b).
1.12 "Royalty Settlement Agreement" means the written royalty
settlement agreements between the State and Exxon Corporation ("Exxon") dated
December 31, 1991.
1.13 "Royalty Value" means the royalty value of all liquid
hydrocarbons from the Prudhoe Bay Unit or the Prudhoe Bay Unit initial
Participating Areas as provided in Article 2.1(b) calculated in accordance with
the Royalty Settlement Agreement for West Coast placements as explained in
Article 2.3.
1.14 "TAPS" means the Trans Alaska Pipeline System.
1.15 "Unit Agreement" means the Prudhoe Bay Unit Agreement
effective April 1, 1977, by and between the Lessees and the State, as amended
from time to time.
2
ARTICLE II
SALE OF ROYALTY OIL
2.1 Quantity.
2.1(a) Prudhoe Bay Unit Quantity. The State agrees to sell to
Tesoro and Tesoro agrees to buy from the State that amount of Oil equal to 30.0
percent of the Daily Royalty Oil (Maximum Quantity). At any time upon six
months and ten days written notice, Tesoro may: (l) decrease the Maximum
Quantity; or (2) terminate this Agreement, in which case Tesoro shall not make
any payments as described in Article 2.11 .
Subject to the limitations in this article, Tesoro may temporarily
decrease or increase the amount of Oil to be tendered, but not the Maximum
Quantity provided in this article. To increase or decrease the amount of Oil to
be tendered, Tesoro must give the State at least six Months and ten Days written
notice. If, however, the increase or decrease is less than ten percent of
Tesoro's then current in-kind nomination, Tesoro must give at least one hundred
Days written notice. In addition, he new tendering will take effect on the
first Day of the Month after the applicable notice period expires.
The volume of Daily Royalty Oil available to the State will vary
and may be interrupted from time to time, and depends upon a variety of factors,
including the rate of production from the Leases. The State disclaims and
Tesoro waives any representation, covenant or warranty, expressed or implied,
that a specific quantity or the total or daily, monthly, average, or aggregate
volume of Royalty Oil will be sold or tendered under this Agreement. The State
warrants that it has good title to the Oil tendered under this Agreement.
3
If the State underlifts or stores Royalty Oil at the Prudhoe Bay
Unit, or if the State recovers underlifted or stored Royalty Oil, the quantity
of Oil tendered under this Agreement shall be calculated as if no Royalty Oil
were underlifted or stored or recovered.
2.1(b) Initial Participating Areas Quantity. The State may
choose, in its sole discretion, to sell to Tesoro, and Tesoro agrees to buy from
the state, oil that is produced solely from the initial Participating Areas of
the Prudhoe Bay Unit, as defined in the Unit Agreement, rather than from all
participating areas and Leases within the Prudhoe Bay Unit. If the State so
elects, the Maximum Quantity of Oil shall equal 35.2 percent of the Royalty Oil
produced from the initial Participating Areas in a Day. If the State so elects,
the terms Daily Royalty Oil, Oil, and Royalty Oil shall have the same meaning
set forth in Article I as limited in this article.
2.2 Quality. The Oil sold shall be the same quality as the
Royalty Oil delivered by the Lessees to the State at the Point of Delivery from
the Prudhoe Bay Unit Area. The quality of the Oil sold may vary from time to
time. The State disclaims, and Tesoro waives, any guarantee, representation, or
warranty, either expressed or implied, of merchantability, fitness for use, or
suitability for any particular use or purpose, or otherwise, of any of the Oil
delivered under this Agreement or as to any specific, average, or overall
quality or characteristic of Oil to be sold or tendered under this Agreement.
Tesoro expressly waives any claim that any liquid hydrocarbons made available to
the State by the Lessees, including such substances as crude oil, condensate,
natural gas liquids, or return oil from the Prudhoe Bay Unit Crude Oil Topping
Plant, that may be blended with crude by the Lessees before the Point of
Delivery and tendered as a common stream by the Lessees to the State as Royalty
Oil are not Oil, for purposes of this Agreement.
4
2.3 Price of the Royalty Oil. The price each Month for Oil
purchased under this Agreement shall be the Royalty Value for that Month of Oil
delivered to the West Coast by Exxon from the Prudhoe Bay Unit production. The
Royalty Value shall be determined according to the Royalty Value calculation
stated in Article 3.2 c) of its Royalty Settlement Agreement, except that the
Average Valdez Netback shall be the West Coast Valdez Netback. Exhibit A is an
illustrative calculation of the price if Tesoro had purchased Oil during the
Month of January, 1995.
If any applicable law of the United States of America or any rule
or regulation promulgated by a federal agency will, in the sole judgment of the
State, operate to prohibit or prevent the State from receiving the full amount
due under the above provision, Tesoro's obligation to pay the amount of the
purchase price in excess of the amount permitted will be suspended or adjusted
to the minimum extent required for the State to comply with that law, rule or
regulation.
2.4 Reopeners.
2.4(a) Export Ban Reopener. Neither Tesoro nor the State
shall have the right to reopen this Agreement, unless the export ban on Alaska
North Slope crude now in effect is lifted. Anytime after the export ban is
lifted, either Tesoro or the State may reopen this Agreement for purchase price
only, by giving the other party one month's prior written notice. Upon issuance
and receipt of a notice to reopen, Tesoro and the State will promptly commence
good faith negotiations in an attempt to establish a new purchase price. If
Tesoro and the State cannot agree on a price within three months after the
written notice to reopen, either Tesoro or the State may terminate this
Agreement upon nine months written notice to the other. The purchase price for
Oil tendered during any period pending termination shall be the price in effect
immediately before giving the
5
notice of intent to reopen. If a new purchase price is agreed to by Tesoro and
the State, the new price shall be effective for Oil delivered in the month
following the Agreement.
2.4(b) Royalty Settlement Agreement Reopener. Tesoro shall
not intervene or otherwise participate in any way regarding litigation, styled
ANS Royalty Litigation. Case No. 1-JU-77-847, any future royalty settlement
agreements with the Lessees, or reopeners or other discussions under or
pertaining to royalty settlement agreements. Any judgment resulting from the
ANS Royalty Litigation, any future royalty settlement agreements, or any
reopener under the Royalty Settlement Agreement shall be conclusively binding
upon Tesoro whether or not Tesoro agrees with or consents to the terms of any
such judgment, settlement, or reopener. Furthermore, Tesoro has no independent
right to invoke any of, the provisions of the Royalty Settlement Agreement. If
the Royalty Value is modified in the future as a result of a modification of the
Royalty Settlement Agreement, a corresponding retroactive modification will be
made to the price term of this Agreement and interest will apply to the
modification, whether resulting in an overpayment or underpayment, as set forth
in Article 5.6. Tesoro agrees to be conclusively bound by any such modification
agreed to by the State and Exxon.
Nevertheless, due to potential unpredictable increased costs to
Tesoro posed by any changes to Article III of the Royalty Settlement Agreement
and/or any changes made under the reopener procedures of Article IV of the
Royalty Settlement Agreement, the State shall give Tesoro notice of such changes
or a Notice of Reopener initiated by Exxon or the State. Such notice shall
include information on the nature of such changes and/or the reopener, the
requested effective date of any such changes or proposed changes, and the
position taken by Exxon and the State. Any changes
6
and/or Reopener action under the Royalty Settlement Agreement will give Tesoro
the right to terminate this contract upon six Months and ten Days written notice
to the State.
2.5 Point and Time of Delivery. Simultaneously with receipt of
its Royalty Oil from its Lessees, the State shall tender the Oil to Tesoro where
the State receives the Royalty Oil from its Lessees. That point presently
agreed to by the State and its Lessees in Article 2.3 of the Field Cost
Agreement is the TAPS Pump Station No. 1 Prudhoe Bay Custody Transfer meter
("Transfer Meter").
2.6 Passage of Title and Risk of Loss. Title and risk of loss to
the Oil sold under this Agreement shall pass from the State to Tesoro for all
purposes when the State tenders the Oil at the Point of Delivery.
2.7 Tesoro's Responsibility. Tesoro shall be responsible for
the Oil after passage of title. Tesoro will indemnify and hold the State
harmless from and against any and all claims, costs, damages (including
reasonably foreseeable consequential damages), expenses, or causes of action
arising from or in connection with any transaction or event which relates to the
Oil after title has passed to Tesoro.
2.8 Transportation Arrangements. Tesoro shall make all necessary
arrangements for transporting the Oil sold under this Agreement from the Point
of Delivery, including satisfaction of line fill obligations and storage tank
bottom requirements of the TAPS, if any. If requested by the State, Tesoro
shall submit specific information concerning its arrangement for transportation
of the Oil sold under this Agreement through and away from the TAPS and for the
resale or other disposal of the Oil. Such information may include the specific
tenders of Oil made to the TAPS and identification of tankers, if any, which
will transport the Oil. In addition, Tesoro will provide the
7
State, if requested by the State, with satisfactory evidence or reasonable
assurance of the existence and continuing validity of adequate arrangements for
the transportation or disposal of the Oil subject to this Agreement. Failure to
provide information, evidence, or assurances requested will, at the State's
election by notice to Tesoro, be a material default under this Agreement.
2.9 Absolute Obligations. The obligations of Tesoro to accept,
pay for, and arrange for the transportation of the Oil tendered or sold under
this Agreement are absolute and will not be excused or discharged by the
operation of any disability of Tesoro, event of force majeure, impracticability
or performance, change in conditions, or any other reason or cause.
2.10 Date of First Delivery. The date of First Delivery will be
the first Day of January 1,1996.
2.11 Performance Guaranty and Reservation Fee. If Tesoro does
not take the Maximum Quantity, Tesoro shall pay to the State, in addition to the
purchase price on the actual quantity taken, an amount equal to .75 percent of
the purchase price per barrel per Day on the difference between the Maximum
Quantity and the actual quantity tendered to and accepted by Tesoro for each Day
Tesoro does not take the Maximum Quantity.
2.12 In-State Processing. Tesoro agrees to use best efforts to
insure that any and all of the Royalty Oil tendered under this Agreement will be
processed through Tesoro's refinery near Nikiski, Alaska, or will be exchanged
for other crude oil which shall be processed at that refinery. "Process" means
the manufacture of refined petroleum products. In no event, however, shall the
quantity of Royalty Oil, which must be processed, be less than 80 percent of the
volume of Royalty Oil tendered under this Agreement. "Exchange" means: (l)
direct trades of equal volumes of crude oil; (2) trades of crude oil involving
either cash or volume adjustments, or both, provided that those
8
adjustments relate solely to quality or location differences; (3) sequential
transactions in which Tesoro receives back crude oil from a party other than the
party which receives the Royalty Oil in a trade from Tesoro; or (4) matching
purchases and sales of crude oil. The terms under which Tesoro receives crude
oil in any exchange shall not differ in any significant term from the terms
under which Tesoro delivered Royalty Oil except for terms which adjust for
differences in quality and location. Tesoro agrees that any trade or exchange
shall not reduce the price to be paid to the State and that trades or exchanges
shall be at no cost or expense to the State.
Tesoro's obligation to process Royalty Oil or exchanged oil
in-State may only be suspended or excused under the provisions of Articles VIII
and XI.
The State may, in its sole discretion, waive the in-State
processing requirement in whole or in part, if State is satisfied that Tesoro is
using its best efforts to process the Royalty Oil tendered or the oil exchanged
for Royalty Oil tendered under this Agreement at Tesoro's Alaska refinery and
that the waiver would not be contrary to the underlying intent of the other
provisions of this Agreement.
ARTICLE III
REPRESENTATION AND OBLIGATIONS OF TESORO
Tesoro warrants, represents, and agrees:
3.1 Good Standing and Due Authorization. Tesoro is, and at all
times during the operation of this Agreement shall remain, a corporation
organized and existing under and by virtue of the laws of the United States or
of any State, territory or the District of Columbia, and qualified to do
business in, and in good standing with, the State of Alaska. Tesoro has all
necessary corporate power
9
to enter into this Agreement and to perform the covenants and obligation under
this Agreement. All necessary corporate action has been taken to authorize
Tesoro to enter into this Agreement and perform its covenants and obligations
under this Agreement.
3.2 Financial Condition. The financial information submitted to
the State is complete and correct and fairly presents Tesoro's financial
condition when the information was submitted to the State. The financial
information was prepared in accordance with generally accepted accounting
principles consistently applied. Since the date the information was submitted,
the condition, business, and properties of Tesoro have not been materially
adversely affected in any way. Tesoro agrees to inform the State immediately
if there is any material adverse change in its condition, business, or
properties which may have an appreciable adverse effect on its ability to
perform under this Agreement. Tesoro, in addition, will immediately inform the
State of any significant change in ownership of Tesoro, affiliates, parent
company, and of any change in Tesoro's operations or Agreements, which may
appreciably affect Tesoro's performance under this Agreement.
3.3 Financial Statements. As soon as possible after the end of
the fiscal year of Tesoro, and in any event within one hundred twenty Days
thereafter, Tesoro will furnish to the State, at Tesoro's sole cost and expense,
a report or a complete copy of a report in a form to be prescribed from time to
time by the State which will include Tesoro's balance sheet as of the close of
the fiscal year and the income statement for that year, prepared in each case in
accordance with generally accepted accounting principles consistently applied by
certified public accountants of recognized standing. For purposes of complying
with this article, Tesoro may submit, and the State will accept, the annual
report of Tesoro Petroleum Corporation filed with the United States Securities
and Exchange Commission pursuant to Sec. 13 or 15 (d) of the Security Exchange
Act of 1934.
1O
ARTICLE IV
MEASUREMENTS AND TESTS
The quantity and quality of Oil sold under this Agreement shall be
determined at the Point of Delivery. Procedures and methods for measuring and
metering the Oil sold under this Agreement shall be in accordance with the
practices then in effect in the Prudhoe Bay Unit.
ARTICLE V
PAYMENTS AND ACCOUNTING
5.1 Initial Billing. The State will send to Tesoro, on or
before the tenth business Day of each Month after delivery of Oil, an invoice
statement of account of all Oil estimated to have been measured at the Transfer
Meter and tendered to Tesoro under this Agreement during the immediately
preceding Month according to the best information available to the State, the
estimated purchase price applicable to those deliveries, and the total amount
due (Initial Billing Invoice). The estimates will be made by the State
according to the best information reasonably available to the State. The State
may render its Initial Billing Invoice to Tesoro based in part upon information
reported by the Lessees to the State, information published by the U.S.
Government, and information published in Platt's Oilgram Price Report or any
other publicly available report. The State shall thereafter adjust its Initial
Billing Invoice under this article as soon as more accurate information
concerning the quantity and purchase price of Oil delivered each Month is
available. The State, however, shall not be required to adjust the Initial
Billing Invoice before the sending of the next Month's invoice statement of
account.
11
5.2 Initial Adjustment. After the Initial Billing Invoice under
Article 5.1, the next Monthly invoice will also state the State's initial
adjustments, plus interest, to be made, if any, to the Initial Billing Invoice
rendered in the immediately preceding Month, in accordance with any additional
or more accurate information which may have become available to the State
("Initial Adjustment Invoice"). Whether or not initial adjustments are made,
however, subsequent adjustments may be made under Article 5.5.
5.3 Subsequent Adjustments. Tesoro acknowledges that after the
Initial Billing and Initial Adjustment Invoices, more accurate information
concerning the quantity of or purchase price for Royalty Oil tendered may become
available to the State. If any such information should later become available
to the State, it shall furnish a corrected invoice statement of account to
Tesoro ("Subsequent Adjustment Invoice") and the State will adjust the amount
previously billed; and Tesoro will pay, or the State will credit or refund, the
amount of any Subsequent Adjustment Invoice plus interest. If the State should
render a Subsequent Adjustment Invoice to Tesoro, any amount to be credited or
refunded from the State to Tesoro or paid by Tesoro to the State will be
refunded or paid within thirty Days after the date of the Subsequent Adjustment
Invoice.
The parties recognize that subsequent adjustments may be necessary
after December 31, 1998, and, accordingly, the provisions of Article V will
survive any termination of this Agreement. Any Subsequent Adjustment Invoice
rendered more than six years after the date of delivery will bear interest for
only six years from the date accrued as defined in Article 5.5. This limitation
on interest does not apply to Subsequent Adjustment Invoices resulting from: (l)
regulatory, reopener or court proceeding (including appeals) commenced during
the six year period
12
whether or not the Tesoro or the State is a party and (2) bona fide audits by
the State of Exxon commenced during the six year period.
5.4 Payment. Tesoro will pay the Initial Billing Invoice on the
third business Day of the month following delivery or within three business Days
after the date of the invoice whichever is later; and the Initial Adjustment
Invoice within three business Days of the date of the invoice and on any
Subsequent Adjustment Invoice within 30 Days of the date of the invoice.
Payment shall be made without any deduction, set off, or withholding, by wire
transfer of immediately available funds to the State's account at the following
address:
State Street Bank & Trust Company
Boston, Massachusetts
ABA #011000028
For credit to the State of Alaska
General Investment Fund, AY01
Account #00657189
Attn: Kim Chan, Public Funds
Payment may be made in such other manner or to such other address
as the State may specify in the invoice statement of account or by other written
notice. All other payments to be made under this Agreement shall be paid in the
same manner. If payment is due on a Saturday, Sunday, or legal holiday of the
place where payment is to be received, payment shall be made on the next
following business Day. It is recognized that the State may bill, and that
Tesoro will pay, amounts that are based upon confidential information held or
received by the State. If confidential information is used as the basis for a
billing, then the State will furnish Tesoro, upon its request, with the
certified statement of the Commissioner that the amounts billed are correct
based upon the best information available to the State. If a dispute concerning
a bill arises, Tesoro agrees to pay the full amount billed by the State, except
for obvious clerical mistakes, pending final resolution of the dispute.
13
5.5 Interest. The Amount of all sums, which are not paid when
due under this Agreement or which are later determined to be due as an
adjustment, shall bear interest from the date accrued until paid in full at the
rate as provided in AS 38.05.135(d) or as that statutory provision may later be
amended. Currently, that interest rate in a calendar quarter is at the rate of
five percentage points above the annual rate charged member banks for advances
by the 12th Federal Reserve District as of the first Day of that calendar
quarter, or at the annual rate of 11 percent, whichever is greater, compounded
quarterly as of the last Day of that quarter. The term "date accrued" means the
date of the "Initial Billing plus three business Days." Interest shall apply to
both adjustments for overpayments and underpayments.
The following illustrates from what date interest will run:
January 1-31,1996--Tesoro takes 1996 January production;
February 9, 1996 -- State sends Tesoro the Initial Billing Invoice
for 1996 January production;
February 14, 1996 (Initial Billing plus three business Days) --
Tesoro must pay the Initial Billing Invoice for January 1996
production. If Tesoro does not pay on this day, the Initial
Billing Invoice bears interest from this date plus a late
payment penalty.
March 8, 1996 -- State sends Tesoro the Initial Adjustment Invoice
for January 1996 production. Tesoro owes the State an
additional sum.
March 13,1996 -- Tesoro must pay the Initial Adjustment Invoice
plus interest from February 14, 1996 throught the payment
date.
14
January 10, 1997 -- State sends Tesoro a Subsequent Adjustment
Invoice for January 1996 production. Tesoro is entitled to a
credit. State pays interest from February 14, 1996 through
January 10, 1997.
April 10, 2006 -- The State is notified by Exxon that, due to a
clerical error, it has revised the Royalty Value for January
1996.
April 17, 2006 -- State sends Tesoro another Subsequent Adjustment
Invoice for January 1996 production after Exxon a reports a
clerical error in its calculation of the Royalty Value.
Tesoro owes the State an additional sum.
May 17, 2006 -- Tesoro must pay the Subsequent Adjustment Invoice
for January 1996 production plus interest from calculated
February 14, 1996 through February 14, 2002. If Tesoro does
not pay the Subsequent Adjustment Invoice on this date,
interest will accrue from February 14, 1996 through the date
the payment is made and Tesoro must also pay a late payment
penalty.
November 10, 2006 -- Court settles dispute between the TAPS
carriers and shippers; Carriers are awarded a higher tariff
for January 1996.
November 30, 2006 -- State sends Tesoro a Subsequent Adjustment
Invoice. Tesoro is entitled to a refund which includes
interest calculated from February 14, 1996 through November
30, 2006.
5.6 Late Payment Penalty. If Tesoro fails to make a full
payment within three business days of the date of either an Initial Billing
Invoice or Initial Adjustment Invoice, or within thirty Days of the date of any
Subsequent Adjustment Invoice, then in addition to the amount due
15
plus interest from the date accrued until the date of actual payment, Tesoro
will pay an amount equal to five percent of the principal payment due as a late
payment penalty.
5.7 Payment to Lessee. At the request of the State in the
invoice statement of account or otherwise in writing, Tesoro shall pay all or
any portion designated by the State of that payment required to be made to one
or more of the Lessees at an address or addresses and in the manner designated
by the State. The payment will be made within the time limit specified in
Article V. The State may authorize and designate a third party to make the
request and designate the amount, manner and place of payment under this
provision. Unless otherwise specified, the balance of the payment due, if any,
and payment for subsequent Months, shall be made in accordance with Article V.
5.8 Payment to Third Parties. The State may direct that Tesoro
pay any amount due or which may become due directly to a third party in a manner
and time as may be directed by the State in written notice to Tesoro if, in the
State's sole discretion, the payment to the third party will assist the State in
monitoring or enforcing this Agreement.
ARTICLE VI
TERM
This Agreement shall become effective upon execution by the
parties. The State's obligation to sell and Tesoro's obligation to buy Royalty
Oil becomes effective immediately. Deliveries under this Agreement shall begin
on January 1, 1996, and shall end December 31, 1998. The provisions of Article
V shall survive the termination of this Agreement.
16
ARTICLE VII
DEFAULT OR TERMINATION
7.1 Default. If any one or more of the following events
("Events of Default") occur, then the State, at the its sole option, may
terminate or suspend its obligation to tender and sell Oil and exercise any one
or more of the rights and remedies provided in this Agreement:
(i) At any time, Tesoro (a) repudiates any of its
covenants or obligations under this Agreement, or (b)
fails, within five Days, after written request from
the State to provide the State with written
affirmation of this Agreement and of Tesoro's
intention to perform under this Agreement (together
with evidence or assurances of transportation
arrangement pursuant to Article 2.8 reasonably
satisfactory to the State);
(ii) Tesoro does not pay in full any sum owed under this
Agreement at the time when payment is due;
(iii) Tesoro fails to observe or perform any of its other
covenants and obligations under Article II;
(iv) Tesoro does not perform any act required or
contemplated under this Agreement and: (a) the
non-performance cannot be cured; (b) the
nonperformance continues for more than thirty Days
after the State has notified Tesoro of its
nonperformance; or (c) Tesoro has failed to perform
the same or any other act required or contemplated
under this Agreement;
17
(v) There is a material adverse change in Tesoro's
condition, business, or property which may appreciably
affect its ability to perform any of its obligations
under this Agreement and Tesoro is unable or unwilling
to give the State adequate assurance of continued
performance either within five Days of a request for
such an assurance or within such other shorter time
period as the State may request under the
circumstances;
(vi) Any representation or warranty made by Tesoro in this
Agreement was materially false or incorrect when made;
or
(vii) Tesoro's failure or inability for any reason
(including reasons beyond Tesoro's control) to
maintain the Security described in Article XV,
notwithstanding Tesoro's continuing willingness and
ability to perform its other obligations and covenants
under the Agreement.
7.2 Failure to Pay Debts. If Tesoro becomes unable to pay any
of its debts when due, or should otherwise become insolvent (regardless how that
insolvency may be evidenced), Tesoro will immediately give written notice of
that fact to the State. Whether that notice is given, if Tesoro becomes unable
to pay any of its debts when due or should otherwise become insolvent, the
State's obligation to tender and sell Oil will automatically and immediately
terminate without any requirement of notice or other action by the State;
however, Tesoro will nevertheless be and remain liable for payment and
performance of all of its obligations and covenants under this Agreement
regarding Oil actually tendered by the State to and after any such termination.
Within thirty Days after receipt of Tesoro's notice or, if no notice is given,
after the State otherwise becomes aware (as
18
determined in the State's sole discretion) of Tesoro's insolvency, the State
will have the right, upon written notice to Tesoro, to reinstate all of the
State's and Tesoro's obligations under this Agreement retroactively to the date
of termination.
7.3 State's Remedies. If any Event of Default occurs or if the
State's obligation to tender and sell Oil under this Agreement is terminated or
suspended, all of Tesoro's obligations accrued but not otherwise due and payable
under this Agreement will immediately be due and payable in full. In addition,
Tesoro will indemnify and hold the State harmless from and against all other
liability, damages (including reasonably foreseeable consequential damages),
costs, losses and expenses (including reasonable attorney's fees and
disbursements) incurred by the State and arising out of the Event of Default,
termination, or suspension. The State shall have the right cumulatively to
exercise any and all other rights and remedies and to obtain all other relief
available under applicable law or at equity, including mandatory injunction and
specific performance.
Additionally, in its sole discretion, the State, upon occurrence
of any Event of Default: (1) may dispose to third parties any or all Royalty Oil
to be tendered and sold under this Agreement and (2) may release Tesoro from the
in-state processing obligations set forth in Article 2.12 until the Event of
Default no longer exists or the obligation of Tesoro to take Oil under this
Agreement expires. If the State disposes of Oil to third parties, or if Tesoro
is released from Article 2.12, whether or not this Agreement is terminated,
Tesoro will nevertheless remain liable for the difference between the purchase
price for that Oil under this Agreement and the price received by the State by
disposition, including all of the expenses (including reasonable attorneys' fees
and costs), and losses incurred by the State arising out of the Event of Default
or disposition.
19
7.4 Tesoro's Exclusive Remedies. Upon any breach of, or default
in performance of any of the State's covenants or obligations under this
Agreement, Tesoro agrees that its remedies will not include a temporary
restraining order or preliminary injunction preventing the State from taking any
action regarding the Royalty Oil which is the subject of this Agreement.
ARTICLE VIII
DISPOSITION OF OIL
8.1 Disposition of Oil Upon Default or Termination. Tesoro
recognizes that the State may be required to give up to six Months notice to the
Lessees (or ninety Days if the amount of increase or decrease is less than ten
percent of the then current nominations or marine transportation is available)
to increase or decrease the amount of Daily Royalty Oil to be taken in-kind.
Tesoro agrees that the State's electing to invoke its rights to return to taking
its Royalty Oil in-value on less than six Month's prior notice, or to attempt to
secure a waiver of any condition or requirement, is at the State's sole
discretion. Notwithstanding termination of this Agreement for any reason,
Tesoro shall continue to take and purchase the State's Royalty Oil in the
amount and for the price set forth in this Agreement for up to six Months
following termination if the State, in its sole discretion, so requires.
8.2 Inability to Receive Oil. If for any reason, Tesoro is
unable or refuses to accept or receive any Oil tendered under this Agreement,
Tesoro shall nevertheless be and remain responsible for the disposal of that Oil
and for paying the State for the Oil as though it had been received and accepted
by Tesoro unless the State, in its sole discretion, elects to waive this
requirement. To secure Tesoro's obligations under Article 8.2 and Article 2.9,
Tesoro shall, if the State requests, assign or otherwise transfer to the State
or its designee all or part right, title and interest
20
of Tesoro under any nominations, Leases, agreements, contracts, charter parties
and other arrangements for the transportation of the Oil sold under this
Agreement through and away from the TAPS; provided, that the State shall not
have any liability or obligations under any such nominations, Leases,
agreements, contracts, charter parties or other arrangement unless, and to the
extent that, the State shall actually exercise its rights to succeed to Tesoro's
interest under them and shall obtain the benefits of them.
8.3 No Right to Storage or Underlift. Tesoro waives and
disclaims any interest or right that it may assert to storage of Royalty Oil,
including by underlift or other means, to which the State is or may become to be
entitled under the Leases or any other agreement.
ARTICLE IX
WAIVER
The failure of either party to insist upon strict performance of
any provision of this Agreement shall not constitute a waiver of, or estoppel
against, asserting the right to require that performance in the future. A
waiver or estoppel in any one instance shall not constitute a waiver or estoppel
with respect to a later breach of a similar nature or otherwise. A course of
performance established by a party shall also not estop the other party from
complaining of a later breach similar in nature.
21
ARTICLE X
VALIDlTY
If any provision or clause of this Agreement or application of this
Agreement is held invalid, that invalidity shall not affect other provisions or
application of this Agreement which can be given effect without the invalid
provision or application. If, however, an invalidity should operate to impair
any material right or remedy of a party to this Agreement, that party may
terminate this Agreement by notice to the other.
ARTICLE XI
FORCE MAJEURE AND CHANGE IN CONDITION
11.1 Effect of Force Majeure. Except for Tesoro's obligations
to pay for Oil tendered and to accept and dispose of Royalty Oil, neither party
shall be liable for any failure to perform when performance is prevented, in
whole or in substantial part, by force majeure after good faith efforts to
perform. The term 'force majeure" shall mean an event or condition not within
the reasonable control of the party claiming the benefit of this excuse. If,
however, any material obligation of Tesoro is excused or suspended by a force
majeure for sixty successive Days or more, the State will have the right to
terminate this Agreement. Before the State exercises its right to terminate,
Tesoro and the State shall in good faith negotiate to restore the benefits and
obligations of the force majeure condition.
11.2 Responsibility. If a party believes that force majeure has
occurred, the party shall immediately notify the other party of its claim of
force majeure. If force majeure occurs, that occurrence shall, so far as
possible, be remedied with reasonable diligence. Except for Tesoro's
22
obligations to pay for Oil tendered and to accept and dispose of Oil, the
disabled party's obligations to perform that are affected by the force majeure
shall be suspended from the time that notification occurs until the disability
should have been remedied with reasonable diligence, and for no longer.
ARTICLE XII
NOTICES
12.1 Method. All notices, requests, demands or statements shall
be in writing, and may be delivered personally, telecopied, or sent by
registered or certified United States mail, postage prepaid, with a return
receipt requested, to the party to be notified. Notice deposited in the mail in
this manner shall be effective upon the expiration of seven Days after it is so
deposited or upon the date of receipt, whichever is earlier. Notice given in
any other manner shall be effective only if and when received by the addressee.
For the purposes of notice, the address of the parties shall be as follows:
If to the State: State of Alaska
Commissioner of Natural Resources
400 Willoughby Avenue
Juneau,Alaska 99801
and
Director, Division of Oil and Gas
P. 0. Box 107034
Anchorage, Alaska 99510-0734
Telecopy Number: (907)562-3852
If to Tesoro:
Gaylon H. Simmons
Tesoro Alaska Petroleum Company
8700 Tesoro Drive
San Antonio, Texas 78217
Telecopy Number: (210) 283-2031
23
12.2 Change of Address. Each party may change its address for
notice by giving written notice of the change.
ARTICLE XIII
RULES AND REGULATIONS
This Agreement is subject to all present and future valid laws,
orders, rules and regulations of the United States, the State of Alaska, and any
duly constituted agency of the State of Alaska.
ARTICLE XIV
SOVEREIGN POWER OF THE STATE
This Agreement shall not be interpreted as a limit on the State of
Alaska's exercise of any of its sovereign or regulatory powers, whether
conferred by constitution, statute or regulation, including, but not limited to,
its regulatory power over the Leases. Its exercise of any sovereign or
regulatory power will not operate or be deemed to enlarge any rights of Tesoro
or to limit or impair any obligations or liability of Tesoro under this
Agreement.
ARTICLE XV
SECURITY
15.1 Letter of Credit. Seventy five Days before the Date of
First Delivery, Tesoro shall cause to be issued and delivered to the State an
irrevocable stand-by letter of credit, with an effective date no later than the
Date of First Delivery, issued for the benefit of the State by a State or
24
national banking institution of the United States ("Issuer"), which is insured
by the Federal Deposit Insurance Corporation and has an aggregate capital and
surplus of not less than One Hundred Million Dollars ($100,000,000), or other
banking institution acceptable to the State in its sole discretion. The
principal face amount of such letter of credit shall be a sum estimated by the
Commissioner, in his sole discretion, to be equal to the aggregate purchase
price for the approximate total amount of Oil to be tendered by the State to
Tesoro during the first seventy five Days following the Date of First Delivery.
The letter of credit shall be in a form satisfactory to the Commissioner, but in
any event shall not require any documents to be submitted in support of drafts
drawn against this letter of credit other than the certified statement of the
Commissioner or his designee and the Attorney General of the State of Alaska or
his designee that Tesoro is liable to the State for a sum equal to the amount of
such draft, and that sum is due and payable in full and has not been timely
paid. The letter of credit must be renewed seventy five Days before its
expiration so that a letter of credit is continuously valid for seventy five
Days after the date of the last delivery of Royalty Oil. If a replacement
letter of credit, in a form satisfactory to the Commissioner in his sole
discretion, is not received seventy five Days before the expiration of the
existing letter of credit, then Tesoro shall be deemed to have materially
breached this Agreement, there shall have occurred an event of default under
Article 7.1, and all obligations of Tesoro accrued, but not otherwise due and
payable under this Agreement, will immediately become due and payable in full.
If the State has reasonable grounds for asserting any claims
against Tesoro and does assert those claims in an aggregate amount in excess of
the aggregate principal face amount of the letter of credit then in effect,
Tesoro shall, upon the State's request (whether or not Tesoro may deny, reject
or otherwise resist such claims), cause the principal face amount to be
increased by an amount
25
equal to the excess. Tesoro shall also automatically increase the principal
face amount, without request from the State, whenever the face amount is less
than the expected purchase price of seventy five Days of Oil tenders, to an
amount equal to the expected purchase price of seventy five Days of Oil tenders.
Upon approval of the State in its sole discretion, Tesoro may decrease the
principal face amount if the face amount is more than the expected purchase
price of seventy five Days of Oil tenders to an amount equal to the expected
purchase price of seventy five Days of Oil tenders.
The letter of credit must allow drafts to be drawn and presented to
the Issuer up to and including the 75th Day after the last delivery of Royalty
Oil to Tesoro under this Agreement. The Commissioner may accept such other or
additional security as he, in his sole discretion, considers adequate to protect
the State.
15.2 Reduction of Term. The term of the letter of credit
required under Article XV shall be reduced from seventy five Days to sixty Days,
if Tesoro and the State can reach an agreement regarding the transportation of
Oil if Tesoro defaults under this Agreement. If the parties cannot reach an
agreement, then the letter of credit shall remain at seventy five Days or Tesoro
shall have the right, in its sole discretion, to terminate this Agreement as
provided in Article 2.1.
ARTICLE XVI
PREFERENTIAL HIRING AND NON-DISCRIMINATION
Tesoro agrees to employ Alaska residents and Alaska companies to
the extent they are available, willing and qualified for all work performed in
Alaska in connection with the Agreement. "Alaska resident" means an individual
who has resided in Alaska for one year at the time of
26
employment and "Alaska companies" means companies incorporated in Alaska or
whose principal place of business is in Alaska.
If this provision is determined to be unconstitutional, then Tesoro
agrees to employ Alaska residents and Alaska companies to the extent such
preferential hiring is determined to be constitutional.
ARTICLE XVII
APPLICABLE LAW
17.1 Alaska Law. This Agreement shall be governed by and
construed in accordance with the laws of the State of Alaska.
17.2 Submission to Jurisdiction. Any legal action or proceeding
arising out of or relating to this Agreement or for the enforcement of the
covenants or obligations of either party must be instituted in a State court of
general jurisdiction sitting in the State of Alaska, and Tesoro hereby
irrevocably submits to the jurisdiction of that court in any such action or
proceeding.
ARTICLE XVIII
WARRANTIES
The purchase and sale of Royalty Oil are subject only to the
warranties of the State expressly set forth in this Agreement and the State
disclaims and Tesoro waives all other warranties, express or implied in law,
whatsoever.
27
ARTICLE XIX
AMENDMENT
This Agreement may be supplemented, amended, or modified only by
written instrument duly executed by the parties.
ARTICLE XX
SUCCESSORS AND ASSIGNS
No assignment, pledge, or encumbrance of this Agreement shall be
made by either party without the written consent of the other party. The
Commissioner or the Commissioner's designee may grant or deny such consent.
Subject to the above requirements in this article, this Agreement will be
binding upon and inure to the benefit of each of the parties and its successors
and permitted assignees.
ARTICLE XXI
HEADINGS
Headings used in this Agreement are for convenience only and shall
not affect its construction.
ARTICLE XXII
RECORDS
22.1 Preservation of Records. Tesoro will preserve and maintain
all books, accounts, and records relating to or arising out of the performance
of this Agreement including, but
28
not limited to, the purchase or sale of Royalty Oil and its refined products,
for a period of no less than six years from the date of transaction or last
adjustment relating to the transaction. Tesoro will also maintain and preserve
all similar books, accounts, and records of which it has possession belonging to
those third parties with whom it contracts for the performance of various parts
of this Agreement. Neither Tesoro nor the State shall be required to retain any
records for more than six years unless retention of such records is specifically
required by applicable law or regulation, or this Agreement. Tesoro shall
either maintain its records within the State of Alaska or make such records
available to the State at Tesoro's principal office in the State of Alaska
within thirty Days after written request by the State.
22.2 Inspection of Records of Parties. Tesoro and the State
will accord to each other and to their authorized agents, attorneys, and
auditors during reasonable business hours access to any and all property,
records, books, documents, and indices directly related to Tesoro's or the
State's performance of this Agreement and which are under the control of the
party from which access is desired so that the other party may inspect,
photograph and make copies of that property, records, books, documents and
indices. The State shall not be required to disclose any information, data, or
records which are required to be held confidential by State or federal law or
regulation, or by agreement. If the information obtained by the State may be
held confidential under State or federal law or regulation, Tesoro may request
that information be held confidential by the State and the State will keep this
information confidential.
29
ARTICLE XXIII
INTERPRETATION OF TERMS AND CONDITIONS
Any disagreement about the meaning or application of a word, term,
or condition in this Agreement will be decided according to the dispute
resolution procedure set forth in this article. Either party may give the other
written notice of a disagreement. Within 60 days after written notice, Tesoro
must present any argument and evidence supporting its view in writing to the
Commissioner for consideration. Tesoro shall not have the right to civil
litigation-type discovery or a civil litigation-type trial with the right to
call or cross-examine witnesses unless granted by the Commissioner in his sole
discretion. The Commissioner will subsequently issue a finding on the meaning
or application of the disputed word, term, or condition, setting forth the basis
for the conclusions. Tesoro agrees to accept findings by the Commissioner under
this article which are supported by substantial evidence.
ARTICLE XXIV
COUNTERPARTS
This Agreement may be executed in multiple counterparts, the
parties need not sign the same counterpart. Each counterpart shall be deemed to
be an original and all of which taken together shall be one and the same
instrument.
30
SIGNATURES
the State: THE STATE OF ALASKA
/s/ John T. Shively
Commissioner
Department of Natural Resources
Date: April 21, 1995
Tesoro Alaska Petroleum Company: TESORO ALASKA PETROLEUM COMPANY
By: /s/ Gaylon H. Simmons
Its: Executive Vice President
Date: April 20, 1995
Tesoro Petroleum Company: TESORO PETROLEUM COMPANY
By: /s/ Gaylon H. Simmons
Its: Executive Vice President
Date: April 20, 1995
31
ACKNOWLEDGEMENT
State of Alaska )
) ss.
Third Judicial District )
THIS IS TO CERTIFY that on the 21 day of April, 1995, before me,
appeared John T. Shively, the commissioner, Department of Natural Resources,
State of Alaska; that Harry A. Noah executed that document under legal authority
and with knowledge of its contents; and that this act was performed freely and
voluntarily upon the premises and for the purposes stated in the document.
Witness my hand and official seal the day and year in this
agreement first above written.
/s/ Sharon Fromming
Notary Public in and for Alaska
My commission expires: 5-24-95
32
ACKNOWLEDGEMENT
State of Texas )
) ss.
County of Bexar)
THIS IS TO CERTIFY that on the 20th day of April, 1995, before me,
appeared Gaylon H. Simmons of Tesoro Alaska Petroleum Company, San Antonio,
Texas; that Gaylon H. Simmons executed that document under legal authority and
with knowledge of its contents; and that this act was performed freely and
voluntarily upon the premises and for the purposes stated in the document.
Witness my hand and official seal the day and year in this
agreement first above written.
/s/ Linda Iden
My commission expires: March 27, 1999
33
ACKNOWLEDGEMENT
State of Texas )
) ss.
County of Bexar)
THIS IS TO CERTIFY that on the 20th day of April, 1995, before me,
appeared Gaylon H. Simmons of Tesoro Petroleum Company, San Antonio, Texas; that
Gaylon H. Simmons executed that document under legal authority and with
knowledge of its contents; and that this act was performed freely and
voluntarily upon the premises and for the purposes stated in the document.
Witness my hand and official seal the day and year in this
agreement first above written.
/s/ Linda Iden
My commission expires: March 27, 1999
34
EXHIBIT A
CALCULATION OF ROYALTY VALUE
This exhibit shows the mechanics of the price calculation and data sources.
Exxon's Royalty Value for the Prudhoe Bay Unit lessees are taken from its
Royalty Report. Royalty Value currently is taken from Column H of these
reports. An example calculation using the information for January 1995 and a
hypothetical RIK volume sold to Tesoro is shown below. Attached are the
Royalty Report Summaries for the Prudhoe Bay Unit.
Exxon's Production Royalty Value Product of Volume Times
from the Prudhoe from Column H Royalty Value
Bay Unit of the Oil
Royalty Report
Summary
Lisburne Production 1,762,900.13 x $11.050 = $19,480,406.44
Center
Prudhoe Bay IPA 8,807,215.20 x $11.110 = $97,848,160.87
------------- ---------------
Total 10,570,115.33 $117,328,207.31
Exxon's Royalty Value = $117,328,207.31 - 10,570,115.33 = $11.09999
Should Article 2.1(b) apply, the Royalty Value will be calculated using the
Royalty Value and production volumes for only the initial Participating Areas.
CALCULATION OF INTEREST
Numbers in these examples are illustrative. They do not represent accurate
values that may have existed in the past or are forecasted for any time in the
future.
Mechanics of the calculations include:
1. The annual interest rate specified in legislation is converted to a
daily rate for calculations.
2. Credits are applied to the next monthly payment. Payment for an
underpayment is due (a) within 3 business of the date the bill is
sent for Initial Billings and initial adjustment or (b) within 30
days of the time the bill is sent for subsequent adjustments.
Interest on overpayments stops accruing on the date of the invoice.
35
Example 1: Initial Billing
Assumptions:
1. Month is February.
2. Royalty Oil delivered to Tesoro in January = 1,240,000 barrels.
3. Royalty Value for January, from Column H of Exxon's Oil Royalty
Report Summaries (attached) = $11.09999.
4. Bill sent to Tesoro on February 1st; Payment due to State by
February 6th (Initial Billing date plus three business days.
Method for calculating Tesoro's initial invoice for January deliveries:
Volume x Price = Initial Billing
1,240,000 x $11.09999 = $13,763,987.60
Note:
The lessees are required to submit their royalty reports to the State for
January's production by the last day in February. For this reason the State
will bill Tesoro for January production based on the December Royalty Value.
This is an interim value and is subject to revision, since the Agreement
requires that Tesoro pay the Monthly Price for the same production month. The
revised price is incorporated in the invoice submitted the following month
(March).
36
Example 2: Initial Adjustment
Assumptions:
1. Month is March.
2. Royalty Oil delivered to Tesoro in January = 1,240,000 barrels.
3. Revised Monthly Price for January = $11.00000.
4. Annual interest rate charged member banks for advances by 12th
Federal Reserve District as of January 1st is three percent.
Annual rate for contract = 11 percent.
5. Date of Initial Adjustment is March 1st.
Method for calculating Tesoro's revised invoice for January deliveries:
Volume x Price = Revised Billing
1,240,000 x $11.00000 = $13,640,000.00
Amount Paid by Tesoro for January deliveries (calculated in Example 1):
$13,763,987.60
--------------
Overpayment for January: ($123,987.60)
Difference between Initial Adjustment date (March 1st) and original accrual date
(February 6th) = 23 days.
Interest due = $123,987.60 x (11%/365) x 23 = ($859.42)
--------------
Credit due Tesoro for next month's billing = ($124,847.02)
37
Example 3: Subsequent Adjustment
This adjustment is assumed to occur after true-up of BP transportation costs, a
reopener for one of the Royalty Settlement Agreements, or for some other
reason. It is assumed to occur June 5th.
Assumptions:
1. Month is June.
2. Royalty Oil delivered to Tesoro in January = 1,240,000 barrels.
3. Adjusted Monthly Price for January = $11.11000.
4. Annual interest rate charged member banks for advances by 12th
Federal Reserve District as of January 1 assumed to be three
percent; as of April 1 and through the third quarter, seven
percent. Annual interest rate for contract = 11 percent for the
first quarter; 12 percent for the second and third quarter.
5. Tesoro is sent notice of underpayment on June 5th.
6. Tesoro's payment is received on July 5th.
Method for calculating Tesoro's revised invoice for January deliveries:
Volume x Price = Revised Billing
1,240,000 x $11.11000 = $13,776,400.00
Amount Paid by Tesoro for January deliveries
(calculated in Example 2): $13,640,000.00
--------------
Underpayment for January deliveries: $136,400.00
Days of interest in first quarter (Initial Billing date plus 3 business days
through March 3 1st)=53
Days of interest in second quarter (April 1 through June 30th)=91
Days of interest in third quarter (July 1 through July 5)=5
Interest for first quarter = $136,400.00 x (11%/365) x 53 = $2,178.66
Interest for second quarter = ($136,400.00 + $2,178.66) x
(12%/365) x 91 = $4,145.97
Interest for third quarter =($136,400.00 + $2,178.66 +
$4,145.97) x (12%/365) x 5 = $234.62
Payment from Tesoro due to the State within 30 days of
invoice date = $142,959.25
If payment in full not received by or on July 5th then additional interest will
accrue from July 6th through the payment receipt date, plus a late payment
penalty will be assessed.
38
The items omitted are a seven page sample summary report which gives examples of
the calculations referred to above.
<TABLE>
Exhibit 11
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INFORMATION SUPPORTING EARNINGS (LOSS)
PER SHARE COMPUTATIONS
(Unaudited)
(In thousands except per share amounts)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
<S> <C> <C> <C> <C>
PRIMARY EARNINGS (LOSS) PER SHARE
COMPUTATION:
Earnings before extraordinary item. . . . $ 7,456 1,230 9,216 8,432
Extraordinary loss on extinguishment of debt . . . - - - ( 4,752)
--------- --------- --------- ---------
Net earnings . . . . . . . . . 7,456 1,230 9,216 3,680
Less dividend requirements on preferred stocks . . - 791 - 2,680
--------- --------- --------- ---------
Net earnings applicable to common stock $ 7,456 439 9,216 1,000
========= ========= ========= =========
Average outstanding common shares. 24,538 22,525 24,525 20,688
Average outstanding common equivalent shares . . . 668 697 638 662
--------- --------- --------- ---------
Average outstanding common and common
equivalent shares . . . . . 25,206 23,222 25,163 21,350
========= ========= ========= =========
Primary Earnings (Loss) Per Share:
Earnings before extraordinary item. . . $ .30 .02 .37 .27
Extraordinary loss on extinguishment of debt . . - - ( .22)
--------- --------- --------- ---------
Net earnings . . . . . . . $ .30 .02 .37 .05
========= ========= ========= =========
FULLY DILUTED EARNINGS (LOSS) PER
SHARE COMPUTATION:
Net earnings applicable to common stock . $ 7,456 439 9,216 1,000
Add dividend requirements on preferred stocks. . . - 791 - 2,680
--------- --------- --------- ---------
Net earnings applicable to common
stock - fully diluted . . $ 7,456 1,230 9,216 3,680
========= ========= ========= =========
Average outstanding common and common
equivalent shares . . . . . . 25,206 23,222 25,163 21,350
Shares issuable on conversion of preferred shares. - 2,473 - 2,976
--------- --------- --------- ---------
Fully diluted shares. . . . . 25,206 25,695 25,163 24,326
========= ========= ========= =========
Fully Diluted Earnings Per Share - Anti-dilutive<F1>$ .30 .02 .37 .05
========= ========= ========= =========
<FN>
<F1> This calculation is submitted in accordance with paragraph 601(b)(11) of
Regulation S-K although it is not required by APB Opinion No. 15 because it
produces an anti-dilutive result.
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM TESORO
PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE SIX MONTH PERIOD
ENDED JUNE 30, 1995, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> JUN-30-1995
<CASH> 7,356
<SECURITIES> 0
<RECEIVABLES> 101,832
<ALLOWANCES> 1,962
<INVENTORY> 62,357
<CURRENT-ASSETS> 183,244
<PP&E> 514,331
<DEPRECIATION> 228,708
<TOTAL-ASSETS> 502,602
<CURRENT-LIABILITIES> 100,293
<BONDS> 189,096
0
0
<COMMON> 4,090
<OTHER-SE> 167,027
<TOTAL-LIABILITY-AND-EQUITY> 502,602
<SALES> 499,830
<TOTAL-REVENUES> 500,039
<CGS> 445,112
<TOTAL-COSTS> 445,112
<OTHER-EXPENSES> 23,327
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,661
<INCOME-PRETAX> 11,349
<INCOME-TAX> 2,133
<INCOME-CONTINUING> 9,216
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 9,216
<EPS-PRIMARY> .37
<EPS-DILUTED> .37
</TABLE>
